10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

þ                               ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2004

OR

o                          TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                to                .

Commission File Number 1-14365

El Paso Corporation

(Exact Name of Registrant as Specified in Its Charter)

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

Telephone Number: (713) 420-2600

Internet Website: www.elpaso.com

Securities registered pursuant to Section 12(b) of the Act:

	Name of Each Exchange
Title of Each Class	on which Registered
Common Stock, par value $3 per share	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes   þ  No  o.

     Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   þ

     Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes   þ  No  o.

     State the aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant.

     Aggregate market value of the voting stock (which consists solely of shares of common stock) held by non-affiliates of the registrant as of June 30, 2004 computed by reference to the closing sale price of the registrant’s common stock on the New York Stock Exchange on such date: $5,066,348,130.

     Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.

     Common Stock, par value $3 per share. Shares outstanding on March 23, 2005: 642,934,481

Documents Incorporated by Reference

     List hereunder the following documents if incorporated by reference and the part of the Form 10-K (e.g., Part I, Part II, etc.) into which the document is incorporated: Portions of our definitive proxy statement for the 2005 Annual Meeting of Stockholders are incorporated by reference into Part III of this report. These will be filed no later than April 30, 2005.

EL PASO CORPORATION

TABLE OF CONTENTS

	Caption	Page
	PART I
Item 1.	Business		1
Item 2.	Properties		25
Item 3.	Legal Proceedings		25
Item 4.	Submission of Matters to a Vote of Security Holders		28
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		29
Item 6.	Selected Financial Data		30
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		32
	Risk Factors and Cautionary Statement for Purposes of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995		76
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		85
Item 8.	Financial Statements and Supplementary Data		89
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		182
Item 9A.	Controls and Procedures		182
Item 9B.	Other Information		184
	PART III
Item 10.	Directors and Executive Officers of the Registrant		185
Item 11.	Executive Compensation		185
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		185
Item 13.	Certain Relationships and Related Transactions		185
Item 14.	Principal Accountant Fees and Services		185
	PART IV
Item 15.	Exhibits, Financial Statement Schedules, and Reports on Form 8-K		186
	Signatures		215
Purchase and Sale Agreement
Indenture
Stock Option Plan for Non-Employee Directors
Amend.No.1 to Stock Option Plan for Non-Employee Directors
1995 Omnibus Compensation Plan Amended and Restated
Amend.No.1 to 1995 Omnibus Compensation Plan
Amend.No.2 to 1995 Omnibus Compensation Plan
Amend.No. 2 to Supplemental Benefits Plan
Senior Executive Survivor Benefit Plan
Key Executive Severance Protection Plan
Director Charitable Award Plan Amended and Restated
Domestic Relocation Policy
Executive Award Plan of Sonat Inc. Amended and Restated
Subsidiaries of El Paso
Consent of PricewaterhouseCoopers LLP (Houston)
Consent of PricewaterhouseCoopers LLP (Detroit)
Consent of Ryder Scott Company, L.P.
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906

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

/d	= per day
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
TBtu	= trillion British thermal units
Tcfe	= trillion cubic feet of natural gas equivalents

     When we refer to natural gas and oil in “equivalents,” we are doing so to compare quantities of oil with quantities of natural gas or to express these different commodities in a common unit. In calculating equivalents, we use a generally recognized standard in which one Bbl of oil is equal to six Mcf of natural gas. Also, when we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.

     When we refer to “us”, “we”, “our”, “ours”, or “El Paso”, we are describing El Paso Corporation and/or our subsidiaries.

i

PART I

ITEM 1. BUSINESS

      We are an energy company originally founded in 1928 in El Paso, Texas. For many years, we served as a regional natural gas pipeline company conducting business mainly in the western United States. From 1996 through 2001, we expanded to become an international energy company through a number of mergers, acquisitions and internal growth initiatives. By 2001, our operations expanded to include natural gas production, power generation, petroleum businesses, trading operations and other new ventures and businesses, in addition to our traditional natural gas pipeline businesses. During this period, our total assets grew from approximately $2.5 billion at December 31, 1995 to over $44 billion following the completion of The Coastal Corporation merger in January 2001. During this same time period, we incurred substantial amounts of debt and other obligations.

      In late 2001 and in 2002, our industry and business were adversely impacted by a number of significant events, including (i) the bankruptcy of a number of energy sector participants, (ii) the general decline in the energy trading industry, (iii) performance in some areas of our business that did not meet our expectations, (iv) credit rating downgrades of us and other industry participants and (v) regulatory and political pressures arising out of the western energy crisis of 2000 and 2001.

      These events adversely affected our operating results, our financial condition and our liquidity during 2002 and 2003. During this two year period, we refocused on our natural gas assets and divested or otherwise sold our interests in a significant number of assets, generating proceeds in excess of $6 billion. As a result of those sales activities and the performance of our businesses during this time period, we also experienced significant losses.

      In late 2003 and early 2004, we appointed a new chief executive officer and several new members of the executive management team. Following a period of assessment, we announced that our long-term business strategy would principally focus on our core pipeline and production businesses. Our businesses are owned through a complex legal structure of companies that reflect the acquisitions and growth in our business from 1996 to 2001. As part of our long range strategy, we are actively working to reduce the complexity of our corporate structure, which is shown below in a condensed format, as of December 31, 2004.

1

Business Segments

      For the year ended December 31, 2004, we had both regulated and non-regulated operations conducted through five business segments — Pipelines, Production, Marketing and Trading, Power and Field Services. Through these segments, we provided the following energy related services:

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.

      During 2004, we also had discontinued operations related to a historical petroleum markets business and international natural gas and oil production operations, primarily in Canada.

2

      Under our long-term business strategy, we will continue to concentrate on our core pipeline and production businesses and activities that support those businesses while divesting or otherwise disposing of our ownership in non-core assets and operations. Our long-term strategy will focus on:

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.

      Below is a discussion of each of our business segments. Our business segments provide a variety of energy products and services. We managed each segment separately and each segment requires different technology and marketing strategies. For additional discussion of our business segments, see Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations. For our segment operating results and identifiable assets, see Part II, Item 8, Financial Statements and Supplementary Data, Note 21, which is incorporated herein by reference.

Regulated Business — Pipelines Segment

      Our Pipelines segment provides natural gas transmission, storage, liquefied natural gas (LNG) terminalling and related services. We own or have interests in approximately 56,000 miles of interstate natural gas pipelines in the United States that connect the nation’s principal natural gas supply regions to the six largest consuming regions in the United States: the Gulf Coast, California, the Northeast, the Midwest, the Southwest and the Southeast. These pipelines represent the nation’s largest integrated coast-to-coast mainline natural gas transmission system. Our pipeline operations also include access to systems in Canada and assets in Mexico. We also own or have interests in approximately 420 Bcf of storage capacity used to provide a variety of flexible services to our customers and an LNG terminal at Elba Island, Georgia.

3

      Our Pipelines segment conducts its business activities primarily through (i) eight wholly owned and four partially owned interstate transmission systems, (ii) five underground natural gas storage entities and (iii) an entity that owns the Elba Island LNG terminalling facility.

Wholly Owned Interstate Transmission Systems

		As of December 31, 2004
									Average Throughput(1)
Transmission	Supply and	Miles of		Design			Storage
System	Market Region	Pipeline		Capacity			Capacity		2004		2003		2002
				(MMcf/d)			(Bcf)				(BBtu/d)
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
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

4

		As of December 31, 2004
									Average Throughput(1)
Transmission	Supply and	Miles of		Design			Storage
System	Market Region	Pipeline		Capacity			Capacity		2004		2003		2002
				(MMcf/d)			(Bcf)				(BBtu/d)
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.

     We also have several pipeline expansion projects underway as of December 31, 2004 that have been approved by the Federal Energy Regulatory Commission (FERC), the more significant of which are presented below:

Transmission						Anticipated
System		Project	Capacity		Description	Completion Date
			(MMcf/d)
	ANR	EastLeg 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
		NorthLeg 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

5

Partially Owned Interstate Transmission Systems

		As of December 31, 2004						Average
								Throughput(3)
Transmission	Supply and	Ownership		Miles of		Design
System(2)	Market Region	Interest		Pipeline(3)		Capacity(3)		2004		2003		2002
		(Percent)				(MMcf/d)		(BBtu/d)
Florida Gas Transmission(4)	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)	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.
(2)	These systems are accounted for as equity investments.
(3)	Miles, volumes and average throughput represent the systems’ totals and are not adjusted for our ownership interest.
(4)	We have a 50 percent equity interest in Citrus Corporation, which owns this system.

     We also have a 50 percent interest in Wyco Development, L.L.C. Wyco owns the Front Range Pipeline, a state-regulated gas pipeline extending from the Cheyenne Hub to Public Service Company of Colorado’s (PSCo) Fort St. Vrain electric generation plant, and compression facilities on WIC’s Medicine Bow Lateral. These facilities are leased to PSCo and WIC, respectively, under long-term leases.

Underground Natural Gas Storage Entities

      In addition to the storage capacity on our transmission systems, we own or have interests in the following 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

      In addition to our pipeline systems and storage facilities, we own an LNG receiving terminal located on Elba Island, near Savannah, Georgia. The facility is capable of achieving a peak sendout of 675 MMcf/d and a base load sendout of 446 MMcf/d. The terminal was placed in service and began receiving deliveries in December 2001. The current capacity at the terminal is contracted with a subsidiary of British Gas, BG LNG Services, LLC. In 2003, the FERC approved our plan to expand the peak sendout capacity of the Elba Island facility by 540 MMcf/d and the base load sendout by 360 MMcf/d (for a total peak sendout capacity once completed of 1,215 MMcf/d and a base load sendout of 806 MMcf/d). The expansion is estimated to cost approximately $157 million and has a planned in-service date of February 2006.

6

Regulatory Environment

      Our interstate natural gas transmission systems and storage operations are regulated by the FERC under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Each of our pipeline systems and storage facilities operates under FERC-approved tariffs that establish rates, terms and conditions for services to our customers. Generally, the FERC’s authority extends to:

      • 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.

      The fees or rates established under our tariffs are a function of our costs of providing services to our customers, including a reasonable return on our invested capital. Our revenues from transportation, storage, LNG terminalling and related services (transportation services revenues) consist of reservation revenues and usage revenues. Reservation revenues are from customers (referred to as firm customers) whose contracts (which are for varying terms) reserve capacity on our pipeline system, storage facilities or LNG terminalling facilities. These firm customers are obligated to pay a monthly reservation or demand charge, regardless of the amount of natural gas they transport or store, for the term of their contracts. Usage revenues are from both firm customers and interruptible customers (those without reserved capacity) who pay usage charges based on the volume of gas actually transported, stored, injected or withdrawn. In 2004, approximately 84 percent of our transportation services revenues were attributable to reservation charges paid by firm customers. The remaining 16 percent of our transportation services revenues are variable. Due to our regulated nature and the high percentage of our revenues attributable to reservation charges, our revenues have historically been relatively stable. However, our financial results can be subject to volatility due to factors such as weather, changes in natural gas prices and market conditions, regulatory actions, competition and the creditworthiness of our customers. We also experience volatility in our financial results when the amount of gas utilized in our operations differs from the amounts we receive for that purpose.

      Our interstate pipeline systems are also subject to federal, state and local pipeline and LNG plant safety and environmental statutes and regulations. Our systems have ongoing programs designed to keep our facilities in compliance with these safety and environmental requirements, and we believe that our systems are in material compliance with the applicable requirements.

Markets and Competition

      We provide natural gas services to a variety of customers including natural gas producers, marketers, end-users and other natural gas transmission, distribution and electric generation companies. In performing these services, we compete with other pipeline service providers as well as alternative energy sources such as coal, nuclear and hydroelectric power for power generation and fuel oil for heating.

      Imported LNG is one of the fastest growing supply sectors of the natural gas market. Terminals and other regasification facilities can serve as important sources of supply for pipelines, enhancing the delivery capabilities and operational flexibility and complementing traditional supply transported into market areas. These LNG delivery systems also may compete with our pipelines for transportation of gas into market areas we serve.

7

      Electric power generation is the fastest growing demand sector of the natural gas market. The growth and development of the electric power industry potentially benefits the natural gas industry by creating more demand for natural gas turbine generated electric power, but this effect is offset, in varying degrees, by increased generation efficiency, the more effective use of surplus electric capacity and increased natural gas prices. The increase in natural gas prices, driven in part by increased demand from the power sector, has diminished the demand for gas in the industrial sector. In addition, in several regions of the country, new additions in electric generating capacity have exceeded load growth and transmission capabilities out of those regions. These developments may inhibit owners of new power generation facilities from signing firm contracts with pipelines and may impair their creditworthiness.

      Our existing contracts mature at various times and in varying amounts of throughput capacity. As our pipeline contracts expire, our ability to extend our existing contracts or re-market expiring contracted capacity is dependent on the competitive alternatives, the regulatory environment at the federal, state and local levels and market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or re-negotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Subject to regulatory constraints, we attempt to re-contract or re-market our capacity at the maximum rates allowed under our tariffs, although we, at times and in certain regions, discount these rates to remain competitive. The level of discount varies for each of our pipeline systems. The table below shows the contracted capacity that expires by year over the next six years and thereafter.

Contract Expirations

8

      The following table details the markets we serve and the competition faced by each of our wholly owned pipeline systems as of December 31, 2004:

Transmission
System	Customer Information	Contract Information	Competition
TGP	Approximately 432 firm and   interruptible customers Major Customers:   None of which individually represents more than 10 percent of revenues	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. 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.
ANR	Approximately 259 firm and interruptible customers Major Customer:   We Energies   (909 BBtu/d)	Approximately 570 firm contracts Weighted average remaining contract term of approximately three years. Contract terms expire in 2005-2010.	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.

9

Transmission
System	Customer Information	Contract Information	Competition
EPNG	Approximately 155 firm and   interruptible customers Major Customer:   Southern California Gas   Company(2)   (475 BBtu/d)    (82 BBtu/d)   (768 BBtu/d)	Approximately 213 firm contracts Weighted average remaining contract term of approximately five years (1)(2). Contract terms expire in 2006. Contract terms expire in 2005 and 2007. Contract terms expire in 2009-2011.	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.
(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.
SNG	Approximately 230 firm   and interruptible   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)	Approximately 203 firm contracts Weighted average remaining contract term of approximately five years. Contract terms expire in 2005-2007. Contract terms expire in 2010-2018. Contract terms expire in 2006-2013. Contract terms expire in 2005-2019.	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.

10

Transmission
System	Customer Information	Contract Information	Competition
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.
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.

11

Transmission
System	Customer Information	Contract Information	Competition
CPG	Approximately 15 firm and   interruptible customers. Major Customers:  Oneok Energy Services     Company L.P.     (195 BBtu/d)  Anadarko Energy Service     Company     (100 BBtu/d)  Kerr McGee     (83 BBtu/d)	Approximately 14 firm contracts Weighted average remaining contract term of approximately 10 years. Contract term expires in 2015. Contract term expires in 2015. Contract term expires in 2015.	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.

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Non-regulated Business — Production Segment

      Our Production segment is engaged in the exploration for, and the acquisition, development and production of natural gas, oil and natural gas liquids, primarily in the United States and Brazil. In the United States, as of December 31, 2004, we controlled over 3 million net acres of leasehold acreage through our operations in 20 states, including Louisiana, New Mexico, Texas, Oklahoma, Alabama and Utah, and through our offshore operations in federal and state waters in the Gulf of Mexico. During 2004, daily equivalent natural gas production averaged approximately 814 MMcfe/d, and our proved natural gas and oil reserves at December 31, 2004, were approximately 2.2 Tcfe.

      As part of our long-term business strategy we will focus on developing production opportunities around our asset base in the United States and Brazil. Our operations are divided into the following areas:

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

      In Brazil, we have been successful with our drilling programs in the Santos and Camamu Basins and are pursuing gas contracts and development options in these two basins. In July 2004, we acquired the remaining 50 percent interest we did not own in UnoPaso, a Brazilian oil and gas company. While we intend to work with Petrobras, a Brazilian national energy company, in growing our presence in the Potiguar Basin with increased production and planned exploratory activity, disputes with them in other areas of our business may impact our plans.

Natural Gas, Oil and Condensate and Natural Gas Liquids Reserves

      The tables below detail our proved reserves at December 31, 2004. Information in these tables is based on our internal reserve report. Ryder Scott Company, an independent petroleum engineering firm, prepared an estimate of our natural gas and oil reserves for 88 percent of our properties. The total estimate of proved reserves prepared by Ryder Scott was within four percent of our internally prepared estimates presented in these tables. This information is consistent with estimates of reserves filed with other federal agencies except for differences of less than five percent resulting from actual production, acquisitions, property sales, necessary reserve revisions and additions to reflect actual experience. Ryder Scott was retained by and reports to the Audit Committee of our Board of Directors. The properties reviewed by Ryder Scott represented 88 percent of our proved properties based on value. The tables below exclude our Power segment’s equity interests in Sengkang in Indonesia and Aguaytia in Peru. Combined proved reserves balances for these interests were 132,336 MMcf of natural gas and 2,195 MBbls of oil, condensate and natural gas liquids (NGL) for total

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natural gas equivalents of 145,507 MMcfe, all net to our ownership interests. Our estimated proved reserves as of December 31, 2004, and our 2004 production are as follows:

		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.

     The table below summarizes our estimated proved producing reserves, proved non-producing reserves, and proved undeveloped reserves as of December 31, 2004:

			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.

     Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data assumes that we can and will make these expenditures and conduct these operations successfully, but future events, including commodity price changes, may cause these assumptions to change. In addition, estimates of proved undeveloped reserves and proved non-producing reserves are subject to greater uncertainties than estimates of proved producing reserves.

      There are numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and projecting the timing of development expenditures, including many factors beyond our control. The reserve data represents only estimates. Reservoir engineering is a subjective process of estimating

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underground accumulations of natural gas and oil that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretations and judgment. All estimates of proved reserves are determined according to the rules prescribed by the SEC. These rules indicate that the standard of “reasonable certainty” be applied to proved reserve estimates. This concept of reasonable certainty implies that as more technical data becomes available, a positive, or upward, revision is more likely than a negative, or downward, revision. Estimates are subject to revision based upon a number of factors, including reservoir performance, prices, economic conditions and government restrictions. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of that estimate. Reserve estimates are often different from the quantities of natural gas and oil that are ultimately recovered. The meaningfulness of reserve estimates is highly dependent on the accuracy of the assumptions on which they were based. In general, the volume of production from natural gas and oil properties we own declines as reserves are depleted. Except to the extent we conduct successful exploration and development activities or acquire additional properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. For further discussion of our reserves, see Part II, Item 8, Financial Statements and Supplementary Data, under the heading Supplemental Natural Gas and Oil Operations.

Acreage and Wells

      The following table details our gross and net interest in developed and undeveloped acreage at December 31, 2004. Any acreage in which our interest is limited to owned royalty, overriding royalty and other similar interests is excluded.

			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.

     Our United States net developed acreage is concentrated primarily in the Gulf of Mexico (47 percent), Utah (14 percent), Texas (9 percent), Oklahoma (8 percent), New Mexico (7 percent) and Louisiana (7 percent). Our United States net undeveloped acreage is concentrated primarily in New Mexico (23 percent), the Gulf of Mexico (22 percent), Louisiana (12 percent), Indiana (8 percent) and Texas (8 percent). Approximately 22 percent, 9 percent and 11 percent of our total United States net undeveloped acreage is held under leases that have minimum remaining primary terms expiring in 2005, 2006 and 2007.

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      The following table details our working interests in natural gas and oil wells at December 31, 2004:

			Productive
			Natural Gas				Productive Oil				Total Productive				Number of Wells
			Wells				Wells				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.

     At December 31, 2004, we operated 2,952 of the 3,225 net productive wells.

      The following table details our exploratory and development wells drilled during the years 2002 through 2004:

			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.

     The information above should not be considered indicative of future drilling performance, nor should it be assumed that there is any correlation between the number of productive wells drilled and the amount of natural gas and oil that may ultimately be recovered.

Net Production, Sales Prices, Transportation and Production Costs

      The following table details our net production volumes, average sales prices received, average transportation costs, average production costs and production taxes associated with the sale of natural gas and oil for each of the three years ended December 31:

				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		—		—

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				2004		2003		2002
	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
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).

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Acquisition, Development and Exploration Expenditures

      The following table details information regarding the costs incurred in our acquisition, development and exploration activities for each of the three years ended December 31:

				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
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.

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     We spent approximately $156 million in 2004, $220 million in 2003 and $275 million in 2002 to develop proved undeveloped reserves that were included in our reserve report as of January 1 of each year.

Regulatory and Operating Environment

      Our natural gas and oil activities are regulated at the federal, state and local levels, as well as internationally by the countries around the world in which we do business. These regulations include, but are not limited to, the drilling and spacing of wells, conservation, forced pooling and protection of correlative rights among interest owners. We are also subject to governmental safety regulations in the jurisdictions in which we operate.

      Our domestic operations under federal natural gas and oil leases are regulated by the statutes and regulations of the U.S. Department of the Interior that currently impose liability upon lessees for the cost of environmental impacts resulting from their operations. Royalty obligations on all federal leases are regulated by the Minerals Management Service, which has promulgated valuation guidelines for the payment of royalties by producers. Our international operations are subject to environmental regulations administered by foreign governments, which include political subdivisions and international organizations. These domestic and international laws and regulations relating to the protection of the environment affect our natural gas and oil operations through their effect on the construction and operation of facilities, water disposal rights, drilling operations, production or the delay or prevention of future offshore lease sales. We believe that our operations are in material compliance with the applicable requirements. In addition, we maintain insurance to limit exposure to sudden and accidental spills and oil pollution liability.

      Our production business has operating risks normally associated with the exploration for and production of natural gas and oil, including blowouts, cratering, pollution and fires, each of which could result in damage to property or injuries to people. Offshore operations may encounter usual marine perils, including hurricanes and other adverse weather conditions, damage from collisions with vessels, governmental regulations and interruption or termination by governmental authorities based on environmental and other considerations. Customary with industry practices, we maintain insurance coverage to limit exposure to potential losses resulting from these operating hazards.

Markets and Competition

      We primarily sell our domestic natural gas and oil to third parties through our Marketing and Trading segment at spot market prices, subject to customary adjustments. As part of our long-term business strategy, we will continue to sell our natural gas and oil production to this segment. We sell our Brazilian natural gas and oil to Petrobras, a Brazilian energy company. We sell our natural gas liquids at market prices under monthly or long-term contracts, subject to customary adjustments. We also engage in hedging activities on a portion of our natural gas and oil production to stabilize our cash flows and reduce the risk of downward commodity price movements on sales of our production.

      The natural gas and oil business is highly competitive in the search for and acquisition of additional reserves and in the sale of natural gas, oil and natural gas liquids. Our competitors include major and intermediate sized natural gas and oil companies, independent natural gas and oil operations and individual producers or operators with varying scopes of operations and financial resources. Competitive factors include price and contract terms and our ability to access drilling and other equipment on a timely and cost effective basis. Ultimately, our future success in the production business will be dependent on our ability to find or acquire additional reserves at costs that allow us to remain competitive.

Non-regulated Business — Marketing and Trading Segment

      Our Marketing and Trading segment’s operations primarily involve the marketing of our natural gas and oil production and the management of our remaining trading portfolio. Our operations in this segment over the past several years have been impacted by a number of significant events both in this business and in the industry. As a result of the deterioration of the energy trading environment in late 2001 and 2002 and the reduced availability of credit to us, we announced in November 2002 that we would reduce our involvement in

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the energy trading business and pursue an orderly liquidation of our historical trading portfolio. In December 2003, we announced that our historical energy trading operations would become a marketing and trading business focused on the marketing and physical trading of the natural gas and oil from our Production segment. Our Marketing and Trading segment’s portfolio is grouped into several categories. Each of these categories includes contracts with third parties and contracts with affiliates that require physical delivery of a commodity or financial settlement. The types of contracts used in this segment are as follows:

•  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.

Additionally, as of December 31, 2004, we had executed contracts with third parties, primarily fixed for floating swaps, that effectively hedged approximately 244 TBtu of our Production segment’s anticipated natural gas production through 2012. In addition to these hedge contracts, as of December 31, 2004, we are a party to other derivative contracts designed to provide price protection to El Paso from declines in natural gas prices in 2005 and 2006. Specifically, these contracts provide El Paso with a floor price of $6.00 per MMBtu on 60 TBtu of our natural gas production in 2005 and 120 TBtu in 2006. In March 2005, we entered into additional contracts that provide El Paso a floor price of $6.00 per MMBtu on 30 TBtu of natural gas production in 2007 and a ceiling price of $9.50 per MMBtu on 60 TBtu of natural gas production in 2006.

•  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.

•  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

      Our Marketing and Trading segment operates in a highly competitive environment, competing on the basis of price, operating efficiency, technological advances, experience in the marketplace and counterparty

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credit. Each market served is influenced directly or indirectly by energy market economics. Our primary competitors include:

•  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.

Non-regulated Business — Power Segment

      Our Power segment includes the ownership and operation of international and domestic power generation facilities as well as the management of restructured power contracts. As of December 31, 2004, we owned or had interests in 37 power facilities in 16 countries with a total generating capacity of approximately 10,400 gross MW. Our commercial focus has historically been either to develop projects in which new long-term power purchase agreements allow for an acceptable return on capital, or to acquire projects with existing above-market power purchase agreements. However, during 2004, we completed the sale of substantially all of our domestic power generation facilities and a significant portion of our domestic power restructuring business. We will continue to evaluate potential opportunities to sell or otherwise divest the remaining domestic assets and a number of international assets, such that our long-term focus will be on maximizing the value of our power assets in Brazil.

      International Power. As of December 31, 2004, we owned or had a direct investment in the following international power plants (only significant assets and investments are listed):

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

21

(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 Part II, Item 8, Financial Statements and Supplementary Data, Note 17 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.

     In addition to the international power plants above, our Power segment also has investments in the following international pipelines:

	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.

     Domestic Power Plants. During 2004, we sold substantially all of our domestic power assets. As of December 31, 2004, we owned or had a direct investment in the following domestic power facilities (only significant assets and investments are listed):

			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.

     Domestic Power Contract Restructuring. In addition to our domestic power plants, we were historically involved in a power restructuring business. This business involved restructuring above-market, long-term power purchase agreements with utilities that were originally tied to older power plants built under the Public Utility Regulatory Policies Act of 1978 (PURPA). These PURPA facilities were typically less efficient and more costly to operate than newer power generation facilities.

      While we are no longer actively restructuring additional power purchase contracts, we continue to manage the purchase and sale of electricity required under the contracts related to Cedar Brakes I and II and continue to perform under the Mohawk River Funding II contracts. We also retained an interest in Mohawk River Funding III, which is an entity that currently has a claim against an entity in bankruptcy related to a previously restructured power contract. During 2004, we completed the sale of Utility Contract Funding (UCF) and signed binding agreements to sell Cedar Brakes I and II. We completed the sale of Cedar Brakes I and II in the first quarter of 2005.

Regulatory Environment & Markets and Competition

      International. Our international power generation activities are regulated by numerous governmental agencies in the countries in which these projects are located. Many of these countries have recently developed

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or are developing new regulatory and legal structures to accommodate private and foreign-owned businesses. These regulatory and legal structures are subject to change (including differing interpretations) over time.

      Many of our international power generation facilities sell power under long-term power purchase agreements primarily with power transmission and distribution companies owned by the local governments where the facilities are located. When these long-term contracts expire, these facilities will be subject to regional market, competitive and political risks.

      Domestic. Our domestic power generation activities are regulated by the FERC under the Federal Power Act with respect to the rates, terms and conditions of service of these regulated plants. Our cogeneration power production activities are regulated by the FERC under PURPA with respect to rates, procurement and provision of services and operating standards. Our power generation activities are also subject to federal, state and local environmental regulations.

Non-regulated Business — Field Services Segment

      Our Field Services segment conducts our midstream activities, which include gathering and processing of natural gas for natural gas producers, primarily in the south Louisiana production area, and held our ownership interests in Enterprise Products Partners, a publicly traded master limited partnership.

      Gathering and Processing Assets. As of December 31, 2004, our gathering systems consisted of 240 miles of pipeline with 665 MMcfe/d of throughput capacity. These systems had average throughput of 203 BBtue/d during 2004. Our processing facilities had operational capacity and volumes as follows:

		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.

In January 2005, we sold to Enterprise the membership interests in two subsidiaries that own and operate natural gas gathering systems and the Indian Springs gathering and processing facilities.

      General and Limited Partner Interests in Enterprise Products Partners, L.P. During 2003, and through September 2004, we held significant interests in GulfTerra Energy Partners, L.P. In September 2004, GulfTerra merged with Enterprise Products Partners, and we sold our ownership interests in GulfTerra along with our interests in processing assets in South Texas in exchange for cash, a 9.9 percent general partner interest in Enterprise, and 13.5 million units in Enterprise. In January 2005, we sold all of our interests in Enterprise and its general partner for cash.

      Regulatory Environment. Some of our operations, owned directly or through equity investments, are subject to regulation by the Railroad Commission of Texas under the Texas Utilities Code and the Common Purchaser Act of the Texas Natural Resources Code. Field Services files the appropriate rate tariffs and operates under the applicable rules and regulations of the Railroad Commission.

      In addition, some of our operations, owned directly or through equity investments, are subject to the Natural Gas Pipeline Safety Act of 1968, the Hazardous Liquid Pipeline Safety Act of 1979 and various environmental statutes and regulations. Each of our pipelines has continuing programs designed to keep the facilities in compliance with pipeline safety and environmental requirements, and we believe that these systems are in material compliance with the applicable requirements.

      Markets and Competition. We compete with major interstate and intrastate pipeline companies in transporting natural gas and NGL. We also compete with major integrated energy companies, independent

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natural gas gathering and processing companies, natural gas marketers and oil and natural gas producers in gathering and processing natural gas and NGL. Competition for throughput and natural gas supplies is based on a number of factors, including price, efficiency of facilities, gathering system line pressures, availability of facilities near drilling and production activity, customer service and access to favorable downstream markets.

Other Operations and Assets

      We currently have a number of other assets and businesses that are either included as part of our corporate activities or as discontinued operations.

Corporate Activities

      Our corporate operations include our general and administrative functions as well as a telecommunications business, a telecommunications facility in Chicago and various other contracts and assets, including those related to our financial services, petroleum ship charter and LNG operations, all of which are insignificant to our results in 2004.

Discontinued Operations

      Our discontinued operations consist of our petroleum markets business and international natural gas and oil production operations, primarily in Canada.

Environmental

      A description of our environmental activities is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 17, and is incorporated herein by reference.

Employees

      As of March 23, 2005, we had approximately 6,400 full-time employees, of which 362 employees in Brazil are subject to collective bargaining arrangements.

Executive Officers of the Registrant

      Our executive officers as of March 23, 2005, are listed below. Prior to August 1, 1998, all references to El Paso refer to positions held with El Paso Natural Gas Company.

		Officer
Name	Office	Since		Age
Douglas L. Foshee	President and Chief Executive Officer of El Paso		2003		45
D. Dwight Scott	Executive Vice President and Chief Financial Officer of El Paso		2002		41
Robert W. Baker	Executive Vice President and General Counsel of El Paso		1996		48
John W. Somerhalder II	Executive Vice President of El Paso and President of El Paso Pipeline Group		1990		48
Lisa A. Stewart	Executive Vice President of El Paso and President of El Paso Production and Non-Regulated Operations		2004		47

      Douglas L. Foshee has been President, Chief Executive Officer, and a Director of El Paso since September 2003. Mr. Foshee became Executive Vice President and Chief Operating Officer of Halliburton Company in 2003, having joined that company in 2001 as Executive Vice President and Chief Financial Officer. In December 2003, several subsidiaries of Halliburton, including DII Industries and Kellogg Brown & Root, filed for bankruptcy protection, whereby the subsidiaries jointly resolved their asbestos claims. Prior to assuming his position at Halliburton, Mr. Foshee was President, Chief Executive Officer, and Chairman of the Board at Nuevo Energy Company. From 1993 to 1997, Mr. Foshee served Torch Energy Advisors Inc. in various capacities, including Chief Operating Officer and Chief Executive Officer.

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      D. Dwight Scott has been Executive Vice President and Chief Financial Officer of El Paso since October 2002. Mr. Scott served as Senior Vice President of Finance and Planning for El Paso from July 2002 to September 2002. Mr. Scott was Executive Vice President of Power for El Paso Merchant Energy from December 2001 to June 2002, and he served as Chief Financial Officer of El Paso Global Networks from October 2000 to November 2001. Prior to that, he served as a managing director in the energy investment banking practice of Donaldson, Lufkin and Jenrette.

      Robert W. Baker has been Executive Vice President and General Counsel of El Paso since January 2004. From February 2003 to December 2003, he served as Executive Vice President of El Paso and President of El Paso Merchant Energy. He was Senior Vice President and Deputy General Counsel of El Paso from January 2002 to February 2003. Prior to that time he held various positions in the legal department of Tenneco Energy and El Paso since 1983.

      John W. Somerhalder II has been an Executive Vice President of El Paso since April 2000, and President of the Pipeline Group since January 2001. He has been Chairman of the Board of Tennessee Gas Pipeline Company, El Paso Natural Gas Company and Southern Natural Gas Company since January 2000 and Chairman of the Board of ANR Pipeline Company and Colorado Interstate Gas Company since January 2001. Prior to that, he was President of Tennessee Gas Pipeline Company and worked in other executive positions in El Paso since 1996.

      Lisa A. Stewart has been an Executive Vice President of El Paso since November 2004, and President of El Paso Production and Non-Regulated Operations since February 2004. Ms. Stewart was Executive Vice President of Business Development and Exploration and Production Services for Apache Corporation from 1995 to February 2004. From 1984 to 1995, Ms. Stewart worked in various positions for Apache Corporation.

Available Information

      Our website is http://www.elpaso.com. We make available, free of charge on or through our website, our annual, quarterly and current reports, and any amendments to those reports, as soon as is reasonably possible after these reports are filed with the SEC. Information about each of our Board members, as well as each of our Board’s standing committee charters, our Corporate Governance Guidelines and our Code of Business Conduct are also available, free of charge, through our website. Information contained on our website is not part of this report.

ITEM 2. PROPERTIES

      A description of our properties is included in Item 1, Business, and is incorporated herein by reference.

      We believe that we have satisfactory title to the properties owned and used in our businesses, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and easements and restrictions that do not materially detract from the value of these properties, our interests in these properties, or the use of these properties in our businesses. We believe that our properties are adequate and suitable for the conduct of our business in the future.

ITEM 3. LEGAL PROCEEDINGS

      Details of the cases listed below, as well as a description of our other legal proceedings are included in Part II, Item 8, Financial Statements and Supplementary Data, Note 17, and is incorporated herein by reference.

      The purported shareholder class actions filed in the U.S. District Court for the Southern District of Texas, Houston Division, are: Marvin Goldfarb, et al v. El Paso Corporation, William Wise, H. Brent Austin, and Rodney D. Erskine, filed July 18, 2002; Residuary Estate Mollie Nussbacher, Adele Brody Life Tenant, et al v. El Paso Corporation, William Wise, and H. Brent Austin, filed July 25, 2002; George S. Johnson, et al v. El Paso Corporation, William Wise, and H. Brent Austin, filed July 29, 2002; Renneck Wilson, et al v. El Paso Corporation, William Wise, H. Brent Austin, and Rodney D. Erskine, filed August 1, 2002; and

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Sandra Joan Malin Revocable Trust, et al v. El Paso Corporation, William Wise, H. Brent Austin, and Rodney D. Erskine, filed August 1, 2002; Lee S. Shalov, et al v. El Paso Corporation, William Wise, H. Brent Austin, and Rodney D. Erskine, filed August 15, 2002; Paul C. Scott, et al v. El Paso Corporation, William Wise, H. Brent Austin, and Rodney D. Erskine, filed August 22, 2002; Brenda Greenblatt, et al v. El Paso Corporation, William Wise, H. Brent Austin, and Rodney D. Erskine, filed August 23, 2002; Stefanie Beck, et al v. El Paso Corporation, William Wise, and H. Brent Austin, filed August 23, 2002; J. Wayne Knowles, et al v. El Paso Corporation, William Wise, H. Brent Austin, and Rodney D. Erskine, filed September 13, 2002; The Ezra Charitable Trust, et al v. El Paso Corporation, William Wise, Rodney D. Erskine and H. Brent Austin, filed October 4, 2002. The purported shareholder class actions relating to our reserve restatement filed in the U.S. District Court for the Southern District of Texas, Houston Division, which have now been consolidated with the above referenced purported shareholder class actions, are: James Felton v. El Paso Corporation, Ronald Kuehn, Jr., Douglas Foshee and D. Dwight Scott; Sinclair Haberman v. El Paso Corporation, Ronald Kuehn, Jr., and William Wise; Patrick Hinner v. El Paso Corporation, Ronald Kuehn, Jr., Douglas Foshee, D. Dwight Scott and William Wise; Stanley Peltz v. El Paso Corporation, Ronald Kuehn, Jr., Douglas Foshee and D. Dwight Scott; Yolanda Cifarelli v. El Paso Corporation, Ronald Kuehn, Jr., Douglas Foshee and D. Dwight Scott; Andrew W. Albstein v. El Paso Corporation, William Wise; George S. Johnson v. El Paso Corporation, Ronald Kuehn, Jr., Douglas Foshee, and D. Dwight Scott; Robert Corwin v. El Paso Corporation, Mark Leland, Brent Austin; Ronald Kuehn, Jr., D. Dwight Scott and William Wise; Michael Copland v. El Paso Corporation, Ronald Kuehn, Jr., Douglas Foshee and D. Dwight Scott; Leslie Turbowitz v. El Paso Corporation, Mark Leland, Brent Austin, Ronald Kuehn, Jr., D. Dwight Scott and William Wise; David Sadek v. El Paso Corporation, Ronald Kuehn, Jr., Douglas Foshee, D. Dwight Scott; Stanley Sved v. El Paso Corporation, Ronald Kuehn, Jr., and William Wise; Nancy Gougler v. El Paso Corporation, Ronald Kuehn, Jr., Douglas Foshee and D. Dwight Scott; William Sinnreich v. El Paso Corporation, Ronald Kuehn, Jr., Douglas Foshee, D. Dwight Scott and William Wise; Joseph Fisher v. El Paso Corporation, Ronald Kuehn, Jr., Douglas Foshee, D. Dwight Scott and William Wise; and Glickenhaus & Co. v. El Paso Corporation, Rod Erskine, Ronald Kuehn, Jr., Brent Austin, William Wise, Douglas Foshee and D. Dwight Scott; Haberman v. El Paso Corporation et al and Thompson v. El Paso Corporation et al. The purported shareholder action filed in the Southern District of New York is IRA F.B.O. Michael Conner et al v. El Paso Corporation, William Wise, H. Brent Austin, Jeffrey Beason, Ralph Eads, D. Dwight Scott, Credit Suisse First Boston, J.P. Morgan Securities, filed October 25, 2002.

      The stayed shareholder derivative actions filed in the United States District Court for the Southern District of Texas, Houston Division are Grunet Realty Corp. v. William A. Wise, Byron Allumbaugh, John Bissell, Juan Carlos Braniff, James Gibbons, Anthony Hall Jr., Ronald Kuehn Jr., J. Carleton MacNeil Jr., Thomas McDade, Malcolm Wallop, Joe Wyatt and Dwight Scott, filed August 22, 2002, and Russo v. William Wise, Brent Austin, Dwight Scott, Ralph Eads, Ronald Kuehn, Jr., Douglas Foshee, Rodney Erskine, PricewaterhouseCoopers and El Paso Corporation filed in September 2004. The consolidated shareholder derivative action filed in Houston is John Gebhart and Marilyn Clark v. El Paso Natural Gas, El Paso Merchant Energy, Byron Allumbaugh, John Bissell, Juan Carlos Braniff, James Gibbons, Anthony Hall Jr., Ronald Kuehn, Jr., J. Carleton MacNeil, Jr., Thomas McDade, Malcolm Wallop, William Wise, Joe Wyatt, Ralph Eads, Brent Austin and John Somerhalder filed in November 2002. The stayed shareholder derivative lawsuit filed in Delaware is Stephen Brudno et al v. William A. Wise et al filed in October 2002.

Environmental Proceedings

      Kentucky PCB Project. In November 1988, the Kentucky Natural Resources and Environmental Protection Cabinet filed a complaint in a Kentucky state court alleging that TGP discharged pollutants into the waters of the state and disposed of PCBs without a permit. The agency sought an injunction against future discharges, an order to remediate or remove PCBs and a civil penalty. TGP entered into interim agreed orders with the agency to resolve many of the issues raised in the complaint. The relevant Kentucky compressor stations are being remediated under a 1994 consent order with the Environmental Protection Agency (EPA). Despite TGP’s remediation efforts, the agency may raise additional technical issues or seek additional remediation work and/or penalties in the future.

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      Toca Air Permit Violation. In June 2003, SNG notified the Louisiana Department of Environmental Quality (LDEQ) that it had discovered possible compliance issues with respect to operations at its Toca Compressor Station. In December 2003, LDEQ issued a Consolidated Compliance Order and Notice of Potential Penalty. SNG’s Toca Compressor Station will invest an estimated $6 million to upgrade the station’s environmental controls in 2005. SNG filed a revised permit application and plan for compliance in January 2004 and paid a penalty of $66,000, resolving the matter.

      Shoup Natural Gas Processing Plant. On December 16, 2003, El Paso Field Services, L.P. received a Notice of Enforcement (NOE) from the Texas Commission on Environmental Quality (TCEQ) concerning alleged Clean Air Act violations at its Shoup, Texas plant. The alleged violations pertained to exceeding the emission limit, testing, reporting, and recordkeeping issues in 2001. On December 29, 2004, TCEQ issued an Executive Director’s Preliminary Report and Petition revising the allegations from the NOE and seeking a penalty of $419,650. We have answered the Petition, disputing the alleged violations and the proposed penalty.

      Corpus Christi Refinery Air Violations. On March 18, 2004, the Texas Commission on Environmental Quality issued an “Executive Director’s Preliminary Report and Petition” seeking $645,477 in penalties relating to air violations alleged to have occurred at our former Corpus Christi, Texas refinery from 1996 to 2000. We filed a hearing request to protect our procedural rights. Pursuant to discussions on March 16, 2005, the parties have reached an agreement in principle to resolve the allegations for $272,097. The parties are drafting the final settlement document formalizing the agreement.

      Coastal Eagle Point Air Issues. Pursuant to the EPA’s Petroleum Refinery Initiative, our former Eagle Point refinery resolved certain claims of the U.S. and the State of New Jersey in a Consent Decree entered in December 2003. The Eagle Point refinery will invest an estimated $3 million to $7 million to upgrade the plant’s environmental controls by 2008. The Eagle Point Refinery was sold in January 2004. We will share certain future costs associated with implementation of the Consent Decree pursuant to the Purchase and Sale Agreement. On April 1, 2004, the New Jersey Department of Environmental Protection issued an Administrative Order and Notice of Civil Administrative Penalty Assessment seeking $183,000 in penalties for excess emission events that occurred during the fourth quarter of 2003, prior to the sale. We have filed an administrative appeal contesting the penalty.

      St. Helens. On November 11, 2003, our St. Helens, Oregon chemical plant discovered a release of ammonia at the facility and reported the release to the National Response Center and state and local contacts on November 12, 2003. On December 3, 2003, the St. Helens plant was sold to Dyno Nobel, Inc. On April 21, 2004, the EPA issued a demand to El Paso Merchant Energy — Petroleum Company for penalties for alleged reporting violations. We responded to the EPA’s demand, and we have fully resolved the alleged violations by paying a penalty of $50,345 and conducting a supplemental project costing $59,581.

      Natural Buttes. On May 19, 2003, we met with the EPA to discuss potential “prevention of significant deterioration” violations due to a de-bottlenecking modification at Colorado Interstate Gas Company’s facility. The EPA issued an Administrative Compliance Order. We are in negotiations with the EPA as to the appropriate penalty and have reserved our anticipated settlement amount.

      Air Permit Violation. In March 2003, the Louisiana Department of Environmental Quality (LDEQ) issued a Consolidated Compliance Order and Notice of Potential Penalty to our subsidiary, El Paso Production Company, alleging that it failed to timely obtain air permits for specified oil and gas facilities. El Paso Production Company requested an adjudicatory hearing on the matter. The hearing has been stayed by agreement to allow El Paso Production Company and LDEQ time to possibly settle this matter. Negotiations are on-going for resolving this matter.

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ITEM  4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

      We held our annual meeting of stockholders on November 18, 2004. Proposals presented for a stockholders’ vote included the election of twelve directors, ratification of the appointment of PricewaterhouseCoopers LLP as independent certified public accountants for the fiscal year 2004, and two stockholder proposals.

      Each of the twelve incumbent directors nominated by El Paso was elected with the following voting results:

Nominee	For		Withheld
John M. Bissell		484,639,859		101,741,034
Juan Carlos Braniff		485,212,690		101,168,202
James L. Dunlap		503,715,688		82,665,204
Douglas L. Foshee		564,694,430		21,686,462
Robert W. Goldman		503,086,283		83,294,609
Anthony W. Hall, Jr.		490,112,165		96,268,727
Thomas R. Hix		563,913,752		22,467,140
William H. Joyce		564,050,375		22,330,518
Ronald L. Kuehn, Jr.		483,437,462		102,943,431
J. Michael Talbert		503,779,161		82,601,731
John L. Whitmire		502,420,108		83,960,784
Joe B. Wyatt		487,881,511		98,499,382

      The appointment of PricewaterhouseCoopers LLP as El Paso’s independent certified public accountants for the fiscal year 2004 was ratified with the following voting results:

	For		Against		Abstain
Proposal to ratify the appointment of PricewaterhouseCoopers LLP as independent certified public accountants		512,328,324		68,245,737		5,806,831

      There were no broker non-votes for the ratification of PricewaterhouseCoopers LLP.

      Two proposals submitted by stockholders were presented for a stockholder vote. One proposal called for stockholder approval of expensing the costs of all future stock options in the annual income statement. The second proposal called for stockholder approval regarding Commonsense Executive Compensation. The first stockholder proposal was approved and the second stockholder proposal was not approved with the following voting results:

	For		Against		Abstain
Stockholder proposal regarding expensing stock options		303,127,387		125,027,119		12,236,275
Stockholder proposal regarding Commonsense Executive Compensation		50,700,938		379,536,201		10,153,643

      We are currently working toward the adoption of an accounting standard on July 1, 2005 that, once adopted, will result in the expensing of all stock options and other stock based compensation. For a further discussion of this standard, see Part II, Item 8, Financial Statements and Supplementary Data, Note 1.

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PART II

ITEM  5.  MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

      Our common stock is traded on the New York Stock Exchange under the symbol EP. As of March 23, 2005, we had 48,629 stockholders of record, which does not include beneficial owners whose shares are held by a clearing agency, such as a broker or bank.

      The following table reflects the quarterly high and low sales prices for our common stock based on the daily composite listing of stock transactions for the New York Stock Exchange and the cash dividends we declared in each quarter:

		High		Low		Dividends
		(Per share)
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

      On February 18, 2005, we declared a quarterly dividend of $0.04 per share of our common stock, payable on April 5, 2005, to shareholders of record as of March 4, 2005. Future dividends will depend on business conditions, earnings, our cash requirements and other relevant factors.

     Odd-lot Sales Program

      We have an odd-lot stock sales program available to stockholders who own fewer than 100 shares of our common stock. This voluntary program offers these stockholders a convenient method to sell all of their odd-lot shares at one time without incurring any brokerage costs. We also have a dividend reinvestment and common stock purchase plan available to all of our common stockholders of record. This voluntary plan provides our stockholders a convenient and economical means of increasing their holdings in our common stock. Neither the odd-lot program nor the dividend reinvestment and common stock purchase plan have a termination date; however, we may suspend either at any time. You should direct your inquiries to Fleet National Bank, care of EquiServe, our exchange agent at 1-877-453-1503.

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ITEM 6. SELECTED FINANCIAL DATA

      The following historical selected financial data excludes certain of our international natural gas and oil production operations and our petroleum markets and coal mining businesses, which are presented as discontinued operations in our financial statements for all periods. The selected financial data below should be read together with Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and Part II, Item 8, Financial Statements and Supplementary Data included in this Annual Report on Form 10-K. These selected historical results are not necessarily indicative of results to be expected in the future.

		As of or for the Year Ended December 31,
					2003			2002
		2004			(Restated)(1)			(Restated)(1)			2001			2000(2)
		(In millions, except per common share amounts)
Operating Results Data:
	Operating revenues	$	5,874		$	6,668		$	6,881		$	10,186		$	6,179
	Income (loss) from continuing operations available to common stockholders(3)	$	(802	)	$	(523	)	$	(1,242	)	$	(223	)	$	481
	Net income (loss)	$	(948	)	$	(1,928	)	$	(1,875	)	$	(447	)	$	665
	Basic income (loss) per common share from continuing operations	$	(1.25	)	$	(0.87	)	$	(2.22	)	$	(0.44	)	$	0.98
	Diluted income (loss) per common share from continuing operations	$	(1.25	)	$	(0.87	)	$	(2.22	)	$	(0.44	)	$	0.95
	Cash dividends declared per common share(4)	$	0.16		$	0.16		$	0.87		$	0.85		$	0.82
	Basic average common shares outstanding		639			597			560			505			494
	Diluted average common shares outstanding		639			597			560			505			506
Financial Position Data:
	Total assets(5)	$	31,383		$	36,942		$	41,923		$	44,271		$	43,992
	Long-term financing obligations(6)		18,241			20,275			16,106			12,840			11,206
	Securities of subsidiaries(6)		367			447			3,420			4,013			3,707
	Stockholders’ equity		3,439			4,352			5,749			6,666			6,145

(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 Part II, Item 8, Financial Statements and Supplementary Data, Note 1 for a further discussion of the restatement.
(2)	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.
(3)	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

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	this merger that totaled approximately $1.5 billion. For further discussions of events affecting comparability of our results in 2004, 2003 and 2002, see Part II, Item 8, Financial Statements and Supplementary Data, Notes 2 through 5.
(4)	Cash dividends declared per share of common stock represent the historical dividends declared by El Paso for all periods presented.
(5)	Decreases in 2002, 2003 and 2004 were a result of asset sales activities during these periods. See Part II, Item 8, Financial Statements and Supplementary Data, Note 3.
(6)	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.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

      Our Management’s Discussion and Analysis includes forward-looking statements that are subject to risks and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed beginning on page 76.

Overview

      Our business purpose is to provide natural gas and related energy products in a safe, efficient and dependable manner. We own North America’s largest natural gas pipeline system and are a large independent natural gas producer. We also own and operate an energy marketing and trading business, a power business, midstream assets and investments, and have an investment in a small telecommunications business. Our power business primarily consists of international assets.

      Since the end of 2001, our business activities have largely been focused on maintaining our core businesses of pipelines and production, while attempting to liquidate or otherwise divest of those businesses and operations that were not core to our long-term objectives, or that were not performing consistently with the expectations we had for them at the time we made the investment. Our overall objective during this period has been to reduce debt and improve liquidity, while at the same time invest in our core business activities. Our actions during this period have significantly impacted our financial condition, with the sale of almost $10 billion of operating assets. These actions have also resulted in significant financial losses through asset impairments, realized losses on asset sales and reduction of income from the businesses sold.

      We believe that 2004 was a watershed year for us. We were able to meet and exceed a number of the goals established under our 2003 Long Range Plan. As part of our efforts in 2004:

•  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.

      As noted above, in 2004, we focused on expanding our pipeline operations and beginning the turnaround of our production business. During the year, we completed major expansions in our pipeline operations, including our Cheyenne Plains project to provide transmission outlets for natural gas supply in the Rocky Mountains, and we are moving forward on our Seafarer and Cypress projects to fulfill demand for natural gas in the southeastern United States, primarily Florida. Additionally, we continue to work in recontracting capacity on our systems and have been successful to date in these efforts. In our production operations, we instituted a new, more rigorous, risk analysis process which emphasizes strict capital discipline. Over the second half of 2004, this process resulted in a shifting of capital to areas with higher returns, improved drilling results and helped us to begin the stabilization of our domestic production. In addition, we have recently made

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several strategic acquisitions of production properties in Texas.

      In 2005, we will continue to work to achieve our long-range goals by:

•  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.

Capital Resources and Liquidity

      We rely on cash generated from our internal operations as our primary source of liquidity, as well as available credit facilities, project and bank financings, proceeds from asset sales and the issuance of long-term debt, preferred securities and equity securities. From time to time, we have also used structured financing transactions that are sometimes referred to as off-balance sheet arrangements. We expect that our future funding for working capital needs, capital expenditures, long-term debt repayments, dividends and other financing activities will continue to be provided from some or all of these sources, although we do not expect to use off-balance sheet arrangements to the same degree in the future. Each of our existing and projected sources of cash are impacted by operational and financial risks that influence the overall amount of cash generated and the capital available to us. For example, cash generated by our business operations may be impacted by, among other things, changes in commodity prices, demands for our commodities or services, success in recontracting existing contracts, drilling success and competition from other providers or alternative energy sources. Collateral demands or recovery of cash posted as collateral are impacted by natural gas prices, hedging levels and the credit quality of us and our counterparties. Cash generated by future asset sales may depend on the condition and location of the assets and the number of interested buyers. In addition, our future liquidity will be impacted by our ability to access capital markets which may be restricted due to our credit ratings, general market conditions, and by limitations on our ability to access our existing shelf registration statement as further discussed in Part II, Item 8, Financial Statements and Supplementary Data, Note 15. For a further discussion of risks that can impact our liquidity, see our risk factors beginning on page 83.

      Our subsidiaries are a significant potential source of liquidity to us and they participate in our cash management program to the extent they are permitted under their financing agreements and indentures. Under the cash management program, depending on whether a participating subsidiary has short-term cash surpluses or requirements, we either provide cash to them or they provide cash to us.

      During 2004, we took additional steps to reduce our overall debt obligations. These actions included entering into a new $3 billion credit agreement and selling entities with substantial debt obligations as follows (in millions):

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.

     For a further discussion of our long-term debt, other financing obligations and other credit facilities, see Part II, Item 8, Financial Statements and Supplementary Data, Note 15.

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      As of December 31, 2004, we had available liquidity as follows (in billions):

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

      In addition to our available liquidity, we expect to generate significant operating cash flow in 2005. We will supplement this operating cash flow with proceeds from asset sales, which we expect will range from $1.8 billion to $2.2 billion over the next 12 to 24 months (of which $0.7 billion has already closed through the filing date of this Form 10-K). We will also utilize proceeds from our financing activities as needed. In March 2005, we completed a $200 million financing at CIG. The proceeds will be used to refinance $180 million of bonds at CIG that will mature in June 2005 and for other general purposes.

      In 2005 we expect to spend between $1.6 billion and $1.7 billion on capital investments mainly in our core pipeline and production businesses. We have also spent approximately $0.3 billion on acquisitions in our natural gas and oil operations in 2005, and may make additional acquisitions during 2005. As of December 31, 2004, our contractual debt maturities for 2005 and 2006 were approximately $0.6 billion and $1.3 billion. Additionally, we had approximately $0.8 billion of zero-coupon debentures that have a stated maturity of 2021, but contain an option whereby the holders can require us to redeem the obligations in February 2006. We currently expect the holders to exercise this right, which combined with our contractual maturities could require us to retire up to $2.1 billion of debt in 2006. So far, in 2005 we have prepaid approximately $0.7 billion of our Euro denominated debt originally scheduled to mature in March 2006 and $0.2 billion of our zero-coupon debentures. As a result of these prepayments, we have reduced our 2006 expected maturities to approximately $1.2 billion which will give us greater financial flexibility next year.

      Finally, in 2005 we may also prepay a number of other obligations including derivative positions in our marketing and trading operations and possibly amounts outstanding for the Western Energy Settlement, among other items. These prepayments could total approximately $1.1 billion. Of this amount, we have already prepaid approximately $240 million of obligations through the transfer of derivative contracts to Constellation Power in March 2005, in connection with the sale of Cedar Brakes I and II.

      Our net available liquidity includes our $3 billion credit agreement. As of December 31, 2004, we had borrowed $1.25 billion as a term loan and issued approximately $1.2 billion of letters of credit under this agreement. The availability of borrowings under this credit agreement and our ability to incur additional debt is subject to various conditions as further described in Part II, Item 8, Financial Statements and Supplementary Data, Note 15, which we currently meet. These conditions include compliance with the financial covenants and ratios required by those agreements, absence of default under the agreements, and continued accuracy of the representations and warranties contained in the agreements. The financial coverage ratios under our $3 billion credit agreement change over time. However, these covenants currently require our Debt to Consolidated EBITDA not to exceed 6.5 to 1 and our ratio of Consolidated EBITDA to interest expense and dividends to be equal to or greater than 1.6 to 1, each as defined in the credit agreement. As of December 31, 2004, our ratio of Debt to Consolidated EBITDA was 4.85 to 1 and our ratio of Consolidated EBITDA to interest expense and dividends was 1.93 to 1.

      Our $3 billion credit agreement is collateralized by our equity interests in TGP, EPNG, ANR, CIG, WIC, Southern Gas Storage Company, and ANR Storage Company. Based upon a review of the covenants contained in our indentures and our other financing obligations, acceleration of the outstanding amounts under the credit agreement could constitute an event of default under some of our other debt agreements. If there was an event of default and the lenders under the credit agreement were to exercise their rights to the collateral, we could be required to liquidate our interests in these entities that collateralize the credit agreement. Additionally, we would be unable to obtain cash from our pipeline subsidiaries through our cash management program in an event of default under some of our subsidiaries’ indentures. Finally, three of our subsidiaries have indentures associated with their public debt that contain $5 million cross-acceleration provisions.

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      We believe we will be able to meet our ongoing liquidity and cash needs through the combination of available cash and borrowings under our $3 billion credit agreement. We also believe that the actions we have taken to date will allow us greater financial flexibility for the remainder of 2005 and into 2006 than we had in 2004. However, a number of factors could influence our liquidity sources, as well as the timing and ultimate outcome of our ongoing efforts and plans. These factors are discussed in detail beginning on page 83.

  Overview of Cash Flow Activities for 2004 Compared to 2003

      For the years ended December 31, 2004 and 2003, our cash flows are summarized as follows:

					2004			2003
					(In billions)
Cash inflows
	Continuing operating activities
		Net loss before discontinued operations			$	(0.8	)	$	(0.5	)
		Non-cash income adjustments				2.4			1.7
		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	)

Cash From Continuing Operating Activities

      Overall, cash generated from continuing operating activities decreased by $1.2 billion largely due to a payment of $0.6 billion related to the principal litigation under the Western Energy Settlement in 2004 and higher cash recovered from margin deposits in 2003. We recovered $0.7 billion of cash in 2003 from our

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margin deposits by substituting letters of credit for cash on deposit as compared to $0.1 billion recovered in 2004.

Cash From Continuing Investing Activities

      For the year ended December 31, 2004, net cash provided by our continuing investing activities was $0.8 billion. During the year, we received net proceeds of approximately $0.9 billion from sales of our domestic power assets as well as $1.0 billion from the sales of our general and limited partnership interests in GulfTerra and various other Field Services assets. We also released restricted cash of $0.6 billion out of escrow, which was paid to the settling parties to the Western Energy Settlement as discussed above.

      Our 2004 capital expenditures included the following (in billions):

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

      In 2005, we expect our total capital expenditures, including acquisitions, to be approximately $1.9 billion, divided approximately equally between our Production and Pipelines segments. In 2004, our Production segment received funds of approximately $110 million from third parties under net profits interest agreements. In March 2005, we purchased all of the interests held by a party to one of these agreements for $62 million. See Part II, Item 8, Financial Statements and Supplementary Data, under the heading Supplemental Natural Gas and Oil Operations, for a further discussion of these agreements.

      In September 2004, we incurred significant damage to sections of our offshore pipeline facilities due to Hurricane Ivan. Cost estimates are currently in the $80 million to $95 million range with damage assessment still in progress. We expect insurance reimbursement with the exception of a $2 million deductible for this event; however the timing of such reimbursements may occur later than the capital expenditures on the damaged facilities which may increase our net capital expenditures for 2005.

      In January 2005, we sold our remaining interests in Enterprise and its general partner for $425 million. We also sold our membership interest in two subsidiaries that own and operate natural gas gathering systems and the Indian Springs processing facility to Enterprise for $75 million. During 2005, we will continue to divest, where appropriate, our non-core assets based on our long-term business strategy, including additional power assets in Asia and other countries (see Part I, Item 1, Business and Part II, Item 8, Financial Statements and Supplementary Data, Note 3, for a further discussion of these divestitures and the asset divestitures of our discontinued operations). The timing and extent of these additional sales will be based on the level of market interest and based upon obtaining the necessary approvals.

Cash From Continuing Financing Activities

      Net cash used in our continuing financing activities was $1.2 billion for the year ended December 31, 2004. During 2004, our significant financing cash inflows included $1.25 billion borrowed as a term loan under our new $3 billion credit agreement. We also had $1.0 billion of cash contributed by our discontinued operations. Of the amount contributed by our discontinued operations, $0.2 billion was generated from operations, $1.2 billion was received as proceeds from the sales of our Eagle Point and Aruba refineries and our international production operations, primarily in western Canada, and $0.4 billion was used to repay long-term debt related to the Aruba refinery.

      Our significant financing cash outflows included net repayments of $0.9 billion on our previous $3 billion revolving credit facilities during 2004, prior to entering into our new $3 billion credit agreement. We also made $2.5 billion of payments to retire third party long-term debt and redeem preferred interests as we continued in our efforts to reduce our overall debt obligations under our Long-Range Plan. See Part II, Item 8, Financial Statements and Supplementary Data, Note 15, for further detail of our financing activities.

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Contractual Obligations and Off-Balance Sheet Arrangements

      In the course of our business activities, we enter into a variety of financing arrangements and contractual obligations. The following discusses those contingent obligations, often referred to as off-balance sheet arrangements. We also present aggregated information on our contractual cash obligations, some of which are reflected in our financial statements, such as short-term and long-term debt and other accrued liabilities; other obligations, such as operating leases; and capital commitments are not reflected in our financial statements.

Off-Balance Sheet Arrangements and Related Liabilities

  Guarantees

      We are involved in various joint ventures and other ownership arrangements that sometimes require additional financial support in the form of financial and performance guarantees. In a financial guarantee, we are obligated to make payments if the guaranteed party fails to make payments under, or violates the terms of, the financial arrangement. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. If they do not, we are required to perform on their behalf. For example, if the guaranteed party is required to deliver natural gas to a third party and then fails to do so, we would be required to either deliver that natural gas or make payments to the third party equal to the difference between the contract price and the market value of the natural gas. We also periodically provide indemnification arrangements related to assets or businesses we have sold. These arrangements include indemnifications for income taxes, the resolution of existing disputes, environmental matters, and necessary expenditures to ensure the safety and integrity of the assets sold.

      We evaluate our guarantees and indemnity arrangements at the time they are entered into and in each period thereafter to determine whether a liability exists and, if so, if it can be estimated. We record accruals when both these criteria are met. As of December 31, 2004, we had accrued $70 million related to these arrangements. As of December 31, 2004, we also had approximately $40 million of financial and performance guarantees and indemnification arrangements not otherwise reflected in our financial statements.

Contractual Obligations

      The following table summarizes our contractual obligations as of December 31, 2004, for each of the years presented (all amounts are undiscounted):

		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 Part II, Item 8, Financial Statements and Supplementary Data, Note 15.
(2)	See Part II, Item 8, Financial Statements and Supplementary Data, Note 17.
(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 Part II, Item 8, Financial Statements and Supplementary Data, Note 17.

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(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.

Commodity-based Derivative Contracts

      We utilize derivative financial instruments in hedging activities, power contract restructuring activities and in our historical energy trading activities. In the tables below, derivatives designated as hedges primarily consist of instruments used to hedge natural gas production. Derivatives from power contract restructuring activities relate to power purchase and sale agreements that arose from our activities in that business and other commodity-based derivative contracts relate to our historical energy trading activities as well as other derivative contracts not designated as hedges.

      The following table details the fair value of our commodity-based derivative contracts by year of maturity and valuation methodology as of December 31, 2004:

				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.

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     The following is a reconciliation of our commodity-based derivatives for the years ended December 31, 2004 and 2003.

						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 Part II, Item 8, Financial Statements, Notes 3 and 5 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 Part II, Item 8, Financial Statements and Supplementary Data, Notes 3 and 5 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.

     The fair value of contract settlements during the period represents the estimated amounts of derivative contracts settled through physical delivery of a commodity or by a claim to cash as accounts receivable or payable. The fair value of contract settlements also includes physical or financial contract terminations due to counterparty bankruptcies and the sale or settlement of derivative contracts through early termination or through the sale of the entities that own these contracts. The change in fair value of contracts during the year represents the change in value of contracts from the beginning of the period, or the date of their origination or acquisition, until their settlement, early termination or, if not settled or terminated, until the end of the period. During 2003, in conjunction with our acquisition of Chaparral, we consolidated a number of derivative contracts. The majority of the value of these contracts was for power purchase agreements and power supply agreements related to power contract restructuring activities conducted by Chaparral.

      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 amount to derivatives designated as hedges beginning in the fourth quarter of 2004. The

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combination of these positions and our Production segment’s other hedges will result in us receiving the following prices on our natural gas production:

	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.

     To stabilize the company’s pricing outlook for 2005 to 2007, our Marketing and Trading segment entered into additional contracts that provide a floor price on a portion of our unhedged production in 2005, 2006 and 2007 and a ceiling price on a portion of our unhedged 2006 production. These contracts, which are reported on a mark-to-market basis, will result in us receiving the following cash prices on our natural gas production:

	Floor		Floor		Ceiling		Ceiling
	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.

Results of Operations

Overview

      Since 2001, we have experienced tremendous change in our businesses. Prior to this time, we had grown through mergers and acquisitions and internal growth initiatives, and at the same time had incurred significant amounts of debt and other obligations. In late 2001, driven by the bankruptcy of a number of energy sector participants, followed by increased scrutiny of our debt levels and credit rating downgrades of our debt and the debt of many of our competitors, our focus changed to improving liquidity, paying down debt, simplifying our capital structure, reducing our cost of capital, resolving substantial contingences and returning to our core natural gas businesses. Accordingly, our operating results during the three year period from 2002 to 2004 have been substantially impacted by a number of significant events, such as asset sales, significant legal settlements and ongoing business restructuring efforts as part of this change in focus.

      As of December 31, 2004, our operating business segments were Pipelines, Production, Marketing and Trading, Power and Field Services. These segments provide a variety of energy products and services. They are managed separately and each requires different technology and marketing strategies. Our businesses are divided into two primary business lines: regulated and non-regulated. Our regulated business includes our Pipelines segment, while our non-regulated business includes our Production, Marketing and Trading, Power and Field Services segments.

      Our management uses EBIT to assess the operating results and effectiveness of our business segments. We define EBIT as net income (loss) adjusted for (i) items that do not impact our income (loss) from continuing operations, such as extraordinary items, discontinued operations and the impact of accounting changes, (ii) income taxes, (iii) interest and debt expense and (iv) distributions on preferred interests of consolidated subsidiaries. Our businesses consist of consolidated operations as well as investments in

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unconsolidated affiliates. We exclude interest and debt expense and distributions on preferred interests of consolidated subsidiaries so that investors may evaluate our operating results independently from our financing methods or capital structure. We believe EBIT is helpful to our investors because it allows them to more effectively evaluate the operating performance of both our consolidated businesses and our unconsolidated investments using the same performance measure analyzed internally by our management. EBIT may not be comparable to measurements used by other companies. Additionally, EBIT should be considered in conjunction with net income and other performance measures such as operating income or operating cash flow.

      Below is a reconciliation of our EBIT (by segment) to our consolidated net loss for each of the three years ended December 31:

									2002
			2004			2003			(Restated)(1)
			(In millions)
Regulated Business
	Pipelines		$	1,331		$	1,234		$	828
Non-regulated Businesses
	Production			734			1,091			808
	Marketing and Trading			(547	)		(809	)		(1,977	)
	Power			(569	)		(28	)		12
	Field Services			120			133			289
		Segment EBIT		1,069			1,621			(40	)
Corporate and other				(214	)		(852	)		(387	)
		Consolidated EBIT		855			769			(427	)
Interest and debt expense				(1,607	)		(1,791	)		(1,297	)
Distributions on preferred interests of consolidated subsidiaries				(25	)		(52	)		(159	)
Income taxes				(25	)		551			641
	Loss from continuing operations			(802	)		(523	)		(1,242	)
Discontinued operations, net of income taxes				(146	)		(1,396	)		(425	)
Cumulative effect of accounting changes, net of income taxes				—			(9	)		(208	)
	Net loss		$	(948	)	$	(1,928	)	$	(1,875	)

⁽¹⁾  See Part II, Item 8, Financial Statements and Supplementary Data, Note 1 for a discussion of the restatement of our 2002 financial statements, which affected our Pipelines segment results and the amounts reported as a cumulative effect of accounting change in 2002.

     As we refocused our activities on our core businesses by divesting of non-core businesses and restructuring our organization, we incurred losses and incremental costs in each year. During this period, we also resolved significant legal contingencies. These items are described in the table below. For a more detailed discussion of these factors and other items impacting our financial performance, see the individual segment

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and other results included in Part II, Item 8, Financial Statements and Supplementary Data, Notes 3 through 5, and 21.

		Operating Segments
								Marketing
								and						Field			Corporate
		Pipelines			Production			Trading			Power			Services			& Other
		(In millions)
2004
Asset and investment impairments, net of gain(loss) on sales(1)		$	20		$	(8	)	$	—		$	(973	)	$	(7	) (2)	$	3
Restructuring charges			(5	)		(14	)		(2	)		(5	)		(1	)		(91	)
	Total	$	15		$	(22	)	$	(2	)	$	(978	)	$	(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.

     In our Pipelines segment, we experienced improved financial performance from 2002 to 2004, benefitting from the completion of a number of expansion projects and from the resolution of significant legal issues related to the western energy crisis of 2001.

      In our Production segment, we have experienced earnings volatility from 2002 to 2004. During this three-year period, our Production segment sold a significant number of natural gas and oil properties which, coupled with a reduced capital spending program, generally disappointing drilling results and mechanical failures on certain wells, produced a steady decline in production volumes during that timeframe. However, in 2004, we benefited from a favorable pricing environment that allowed for better than anticipated results. The favorable pricing environment is expected to continue to provide benefits to the Production segment during 2005, although its future results will largely be impacted by our production levels. The volumes we produce will be driven by our ability to grow the existing reserve base through a successful drilling program and/or acquisitions.

      In our Marketing and Trading segment, we also experienced significant earnings volatility during 2002, 2003 and 2004. Beginning in 2002, we began a process of exiting the trading business. At the same time, the overall energy trading industry has declined. The combination of these actions and events and a decrease in the value of our fixed-price natural gas derivative contracts due to natural gas price increases resulted in substantial losses in our Marketing and Trading segment in 2002, 2003 and 2004. We expect that this segment will continue to experience losses in 2005 as it continues performing under its transportation and tolling contracts. However, due to the repositioning of a number of our natural gas derivative contracts as hedges in December 2004, we expect future losses in this segment to be less than those experienced in 2002 through 2004.

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      Finally, during 2002 through 2004, as we continued to refocus and restructure our company around our core businesses, we incurred significant charges related to asset sales, impairments and other restructuring costs in our Field Services and Power segments as well as in our corporate results. We also incurred approximately $2.0 billion (including $1.4 billion during 2003) in after tax losses in exiting certain of our international natural gas and oil production operations and our petroleum markets and coal businesses, which are classified as discontinued operations.

      Below is a further discussion of the year over year results of each of our business segments, our corporate activities and other income statement items.

Individual Segment Results

      The results for 2002 of our Pipelines segment presented and discussed below have been restated for errors resulting from a misinterpretation of the provisions of SFAS Nos. 141 and 142 upon the adoption of these standards. See Part II, Item 8, Financial Statements and Supplementary Data, Note 1 for a further discussion of the restatement.

Regulated Business — Pipelines Segment

      Our Pipelines segment consists of interstate natural gas transmission, storage, LNG terminalling and related services, primarily in the United States. We face varying degrees of competition in this segment from other pipelines and proposed LNG facilities, as well as from alternative energy sources used to generate electricity, such as hydroelectric power, nuclear, coal and fuel oil.

      The FERC regulates the rates we can charge our customers. These rates are a function of the cost of providing services to our customers, including a reasonable return on our invested capital. As a result, our revenues have historically been relatively stable. However, our financial results can be subject to volatility due to factors such as changes in natural gas prices and market conditions, regulatory actions, competition, the creditworthiness of our customers and weather. In 2004, 84 percent of our transportation service, storage and LNG terminalling revenues were attributable to reservation charges paid by firm customers. The remaining 16 percent of our revenues are variable. We also experience earnings volatility when the amount of natural gas utilized in operations differs from the amounts we receive for that purpose.

      Historically, much of our business was conducted through long-term contracts with customers. However, over the past several years some of our customers have shifted from a traditional dependence solely on long-term contracts to a portfolio approach which balances short-term opportunities with long-term commitments. This shift, which can increase the volatility of our revenues, is due to changes in market conditions and competition driven by state utility deregulation, local distribution company mergers, new supply sources, volatility in natural gas prices, demand for short-term capacity and new power plants markets.

      In addition, our ability to extend existing customer contracts or re-market expiring contracted capacity is dependent on the competitive alternatives, the regulatory environment at the federal, state and local levels and market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Subject to regulatory constraints, we attempt to re-contract or re-market our capacity at the maximum rates allowed under our tariffs, although, at times, we discount these rates to remain competitive. The level of discount varies for each of our pipeline systems. Our existing contracts mature at various times and in varying amounts of throughput capacity. We continue to manage our recontracting process to limit the risk of significant impacts on our revenues. The weighted average remaining

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contract term for active contracts is approximately five years as of December 31, 2004. Below is the expiration schedule for contracts executed as of December 31, 2004, including those whose terms begin in 2005 or later.

			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

      Below are the operating results and analysis of these results for our Pipelines segment for each of the three years ended December 31:

									2002
Pipelines Segment Results			2004			2003			(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.

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     The following contributed to our overall EBIT increases in 2004 as compared to 2003 and in 2003 as compared to 2002:

		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.

     The following provides further discussion on the items listed above as well as an outlook on events that may affect our operations in the future.

      Contract Modifications/Terminations. Included in this item are (i) the impacts of the expiration of EPNG’s historical risk sharing provisions which reduced revenues by $24 million in 2004 (ii) the impact of EPNG’s FERC ordered restrictions on remarketing expiring capacity contracts which reduced EPNG’s 2003 revenues by $35 million compared to 2002 (iii) the renegotiation or restructuring of several contracts on our pipeline systems, including ANR’s contracts with We Energies which contributed to the decrease in revenues by $36 million in 2004 and $12 million in 2003, and (iv) the termination of the Dakota gasification facility contract on ANR’s system, which resulted in lower operating revenues and lower operating expenses during 2004, without a significant overall impact on operating income and EBIT.

      During 2003, EPNG was prohibited from remarketing expiring capacity contracts due to certain FERC orders. While these capacity restrictions terminated with the completion of Phases I and II of EPNG’s Line 2000 Power-up project in 2004, EPNG remains at risk for that portion of capacity which was turned back to it on a permanently released basis. EPNG is able, however, to re-market that capacity subject to the general requirement that it demonstrate that any sale of capacity does not adversely impact its service to its firm customers.

      EPNG has entered into an agreement effective September 1, 2006, to extend 750 MMcf/d of capacity on its pipeline system with SoCalGas. The new service agreements will have a primary term of three to five years to serve SoCalGas’ core customers. SoCalGas is currently contracted on EPNG’s system for approximately 1.3 Bcf/d of capacity. EPNG continues in its efforts to market the remaining capacity, including marketing efforts to serve, directly or indirectly, SoCalGas’ non-core customers or to serve new markets. At this time, we are uncertain whether this remaining capacity will be re-contracted.

      Guardian Pipeline, which is owned in part by We Energies, currently provides a portion of We Energies’ firm transportation requirements and, therefore, directly competes with ANR for a portion of the markets in Wisconsin. This could impact ANR’s existing customer contracts as well as future contractual negotiations with We Energies. In addition, ANR has entered into an agreement with a shipper to restructure one of its transportation contracts on its Southeast Leg as well as a related gathering contract. In March 2005, this

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restructuring was completed and ANR received approximately $26 million, which will be included in its earnings during the first quarter of 2005.

      Gas Not Used in Operations and Other Natural Gas Sales. For some of our regulated pipelines, the financial impact of operational gas, net of gas used in operations is based on the amount of natural gas we are allowed to recover and dispose of according to the applicable tariff, relative to the amounts of gas we use for operating purposes, and the price of natural gas. The disposition of gas not needed for operations results in revenues to us, which are driven by volumes and prices during the period. During 2003 and 2004, we recovered, fairly consistently, volumes of natural gas that were not utilized for operations for some of our regulated pipeline systems. These recoveries were and are based on factors such as system throughput, facility enhancements and the ability to operate the systems in the most efficient and safe manner. Additionally, a steadily increasing natural gas price environment during this timeframe also resulted in favorable impacts on our operating results in both 2004 versus 2003 and in 2003 versus 2002. We anticipate that this area of our business will continue to vary in the future and will be impacted by things such as rate actions, some of which have already been implemented, efficiency of our pipeline operations, natural gas prices and other factors.

      Expansions. During the three years ended December 31, 2004, we completed a number of expansion projects that have generated or will generate new sources of revenues the more significant of which were our ANR WestLeg Expansion, SNG South System Expansions, TGP South Texas Expansion and CIG Front Range Expansion. Our expansions during this three year period added approximately 1,968 MMcf/d to our overall pipeline system.

      Our pipeline systems connect the principal gas supply regions to the largest consuming regions in the U.S. We are well-positioned to capture growth opportunities in the Rocky Mountains and deepwater Gulf of Mexico, and have an infrastructure that complements LNG growth. We are aggressively seeking to attach new supplies of natural gas to our systems in order to maintain an adequate supply of gas to serve our growing markets and to replace quantities lost due to the natural decline in production from wells currently attached to our system.

      Expansion projects currently in process include:

      Rocky Mountain Expansions. In order to provide an outlet for the growing supply of Rocky Mountain natural gas to markets in the Midwest region of the United States, we have several expansion projects that will increase our transportation capacity, subject to regulatory approval as follows:

•  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.

      LNG Related Expansions and Other. In order to help serve the growing electrical generation needs in the state of Florida, we (i) have commenced a 3.5 Bcf expansion at our Elba Island LNG facility, which is targeted to be completed in the first quarter of 2006, (ii) have begun developing our Cypress Project, which will transport these additional supplies into the Florida market, and (iii) have filed an application with the FERC for authority to construct and operate the U.S. portion of the proposed Seafarer natural gas

46

pipeline, which will transport natural gas from an LNG facility in the Bahamas to southern Florida.

      On our TGP and ANR systems, we continue to experience intense competition along their mainline corridors; however, both are well-positioned to provide transportation service from discoveries in the deepwater Gulf of Mexico and LNG supply growth along the Gulf Coast. These new supplies are expected to offset the continued decline of production from the Gulf of Mexico shelf. Additionally, TGP is developing its ConneXion Expansions in the Northeast market area and ANR is proceeding with its Eastleg and Northleg expansions in its Wisconsin market area.

      Other Regulatory Matters. In November 2004, the FERC issued a proposed accounting release that may impact certain costs our interstate pipelines incur related to their pipeline integrity programs. If the release is enacted as written, we would be required to expense certain future pipeline integrity costs instead of capitalizing them as part of our property, plant and equipment. Although we continue to evaluate the impact of this potential accounting release, we currently estimate that if the release is enacted as written, we would be required to expense an additional amount of pipeline integrity expenditures in the range of approximately $25 million to $41 million annually over the next eight years.

      In 2003, we re-applied Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation, on our CIG and WIC systems, resulting in income from recording the regulatory assets of these systems. SFAS No. 71 allows a company to capitalize items that will be considered in future rate proceedings and $18 million in income resulted from the capitalization of those items that we believe will be considered in CIG’s and WIC’s future rate cases. At the same time CIG and WIC re-applied SFAS No. 71, they adopted the FERC depreciation rate for their regulated plant and equipment. This change resulted in an increase in depreciation expense of approximately $9 million in 2004, an increase which will continue in the future. As of December 31, 2004, ANR Storage Company re-applied SFAS No. 71 which had an immaterial impact and also adopted the FERC depreciation rate which will result in future depreciation expense increases of approximately $4 million annually.

      Our pipeline systems periodically file for changes in their rates which are subject to the approval of the FERC. Changes in rates and other tariff provisions resulting from these regulatory proceedings have the potential to negatively impact our profitability. Listed below is a status of our rate proceedings:

•  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.

      Our other pipelines have no requirements to file new rate cases and expect to continue operating under their existing rates.

      Australian Impairment. In 2002, our impairment of EPIC Energy Australia Trust of $141 million occurred due to an unfavorable regulatory environment, increased competition and operational complexities in Australia. During the second quarter of 2004, we substantially exited our investments in Australian operations.

      Western Energy Settlement. In 2003, El Paso entered into the Western Energy Settlement. EPNG was a party to that settlement and recorded a charge in its 2002 operating expenses of $412 million for its share of the expected settlement amounts. This charge represented the value of El Paso stock and cash that EPNG paid to the settling parties. In the second quarter of 2003, the settlement was finalized and EPNG recorded an additional net pretax charge of $127 million. Also during 2003, accretion expense and other miscellaneous charges of $13 million were recorded and included in operating expenses.

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Non-regulated Business — Production Segment

      Our Production segment conducts our natural gas and oil exploration and production activities. Our operating results are driven by a variety of factors including the ability to locate and develop economic natural gas and oil reserves, extract those reserves with minimal production costs, sell the products at attractive prices and minimize our total administrative costs.

      Our long-term strategy includes developing our production opportunities primarily in the United States and Brazil, while prudently divesting of production properties outside of these regions. We emphasize strict capital discipline designed to improve capital efficiencies through the use of standardized risk analysis and a heightened focus on cost control. We also implemented a more rigorous process for booking proved natural gas and oil reserves, which includes multiple layers of reviews by personnel independent of the reserve estimation process. Our plan is to stabilize production by improving the production mix across our operating areas and to generate more predictable returns. We intend to improve our production mix by allocating more capital to long-life, slower decline projects and to develop projects in longer reserve life areas. This is being accomplished through our more rigorous capital review process and a more balanced allocation of our capital to development and exploration projects, supplemented by acquisition activities with low-risk development locations that provide operating synergies with our existing operations. In January 2005, we announced two acquisitions in east Texas and south Texas for $211 million. In March 2005, we acquired the interests held by one of the parties under our net profits interest agreements for $62 million. See Part II, Item 8, Financial Statements and Supplementary Data, under the heading Supplemental Natural Gas and Oil Operations for a further discussion of these net profits interest agreements. These acquisitions added properties with approximately 139 Bcfe of existing proved reserves and 52 MMcfe/d of current production. More importantly, the Texas acquisitions offer additional exploration upside in two of our key operating areas.

Reserves, Production and Costs

      Our estimate of proved natural gas and oil reserves as of December 31, 2004 reflects 2.0 Tcfe of proved reserves in the United States and 0.2 Tcfe of proved reserves in Brazil. These estimates were prepared internally by us. Ryder Scott Company, an independent petroleum engineering firm, prepared an estimate of our natural gas and oil reserves for 88 percent of our properties. The total estimate of proved reserves prepared by Ryder Scott is within four percent of our internally prepared estimates. Ryder Scott was retained by and reports to the Audit Committee of our Board of Directors. The properties reviewed by Ryder Scott represented 88 percent of our properties based on value. For additional information on our estimated proved reserves and the processes by which they are developed, see Part I, Item 1, Business, Non- regulated Business — Production Segment, Part I, Item 7, Critical Accounting Policies and Risk Factors, and Part II, Item 8, Financial Statements and Supplementary Data, under the heading Supplemental Natural Gas and Oil Operations.

      For 2004, our total equivalent production declined 112 Bcfe or 27 percent as compared to 2003. The decrease was due to steep production declines in our Texas Gulf Coast and offshore Gulf of Mexico regions, the sale of properties in Oklahoma and New Mexico at the end of the first quarter of 2003, and a significantly reduced capital expenditure program in 2004 compared to 2003. We began to see our production stabilize in the third and fourth quarters of 2004 as we instituted our more rigorous capital review process and a more balanced allocation of our capital described above. Our depletion rate is determined under the full cost method of accounting. Due to disappointing drilling performance in 2004 that resulted in higher finding and development costs, we expect our domestic unit of production depletion rate to increase from $1.80/Mcfe in the fourth quarter of 2004 to $1.97/Mcfe in the first quarter of 2005. Our future trends in production and depletion rates will be dependent upon the amount of capital allocated to our Production segment, the level of success in our drilling programs and any future sale or acquisition activities relating to our proved reserves.

Production Hedge Position

      As part of our overall strategy, we hedge our natural gas and oil production to stabilize cash flows, reduce the risk of downward commodity price movements on our sales and to protect the economic assumptions

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associated with our capital investment programs. We conduct our hedging activities through natural gas and oil derivatives on our natural gas and oil production. Because this hedging strategy only partially reduces our exposure to downward movements in commodity prices, our reported results of operations, financial position and cash flows can be impacted significantly by movements in commodity prices from period to period. For 2005, we expect to have hedged approximately 50 percent of our anticipated daily natural gas production and approximately 8 percent of our anticipated daily oil production. Below are the hedging positions on our anticipated natural gas and oil production as of December 31, 2004:

     Natural Gas

	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

      The hedged natural gas prices listed above for 2005 and 2006 include the impact of designating trading contracts in our Marketing and Trading segment as hedges of our anticipated natural gas production on December 1, 2004. For a summary of the overall cash price El Paso will receive on natural gas production including the effect of these contracts, see Commodity-based Derivative Contracts beginning on page 38.

Operational Factors Affecting the Year Ended December 31, 2004

      During 2004, our Production segment experienced the following:

•  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.

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•  Sale of Canadian and other international operations. These operations were sold in order to focus our operations in the United States and Brazil.

Operating Results

Below are our Production segment’s operating results and analysis of these results for each of the three years ended December 31:

			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

						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.

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⁽⁴⁾  Prices are stated before transportation costs.

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

      Our EBIT for 2004 decreased $357 million as compared to 2003. Despite an eight percent increase in natural gas prices including hedges, we experienced a significant decrease in operating revenues due to lower production volumes as a result of normal production declines, asset sales, a lower capital spending program and disappointing drilling results. The table below lists the significant variances in our operating results in 2004 as compared to 2003:

			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.

     Operating revenues. In 2004, we experienced a significant decrease in production volumes. The decline in our production volumes was due to normal production declines in the Offshore Gulf of Mexico and Texas Gulf Coast regions, asset sales, the impact of hurricanes in the Gulf of Mexico, lower capital expenditures and disappointing drilling results. These declines were partially offset by increased natural gas production in our coal seam operations in the Raton, Arkoma, and Black Warrior basins. We also had increased oil production in Brazil as a result of our acquisition of the remaining interest in UnoPaso in July 2004. In addition, we experienced higher average realized prices for natural gas and oil, condensate and NGL and a favorable impact from our hedging program as our hedging losses were $18 million in 2004 as compared to $44 million in 2003.

      Depreciation, depletion, and amortization expense. Lower production volumes in 2004 due to the production declines discussed above reduced our depreciation, depletion, and amortization expense. Partially offsetting this decrease were higher depletion rates due to higher finding and development costs.

      Production costs. In 2004, we experienced higher workover costs due to the implementation of programs in the second half of 2004 to improve production in the Offshore Gulf of Mexico and Texas Gulf Coast regions. We also incurred higher utility expenses and higher salt water disposal costs in the Onshore region. More than offsetting these increases were lower production taxes as a result of higher tax credits taken in 2004 on high cost natural gas wells. The cost per unit increased due to the higher lease operating costs and lower production volumes discussed above.

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      Other. Our general and administrative expenses increased primarily due to higher contract labor costs and lower capitalized costs in 2004. The cost per unit increased due to a combination of higher costs and lower production volumes discussed above.

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

      Our EBIT for 2003 increased $283 million as compared to 2002. For the year ended December 31, 2003, natural gas prices, including hedges, increased 61 percent; however, we also experienced a significant decrease in production volumes as a result of asset sales, normal production declines, mechanical failures in several of our producing wells, a lower capital spending program and disappointing drilling results. The table below lists the significant variances in our operating results in 2003 as compared to 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.

     Operating revenues. During 2003, we experienced a significant decrease in production volumes due to the sale of properties in New Mexico, Oklahoma, Texas, Colorado, Utah, and Offshore Gulf of Mexico, normal production declines, mechanical failures primarily in the Texas Gulf Coast and Offshore Gulf of Mexico regions, a lower capital spending program and disappointing drilling results. In addition, we incurred an unfavorable impact from our hedging program as our hedging losses were $44 million in 2003 as compared to $82 million of hedging gains in 2002. Despite lower production and unfavorable hedging results, revenues were higher due to higher average realized prices for natural gas and oil, condensate and NGL during 2003.

      Depreciation, depletion, and amortization expense. Lower volumes in 2003 due to the production declines discussed above reduced our depreciation, depletion, and amortization expense. Partially offsetting this decrease were higher depletion rates due to higher finding and development costs. We also recorded accretion expense related to our liabilities for asset retirement obligations in connection with the adoption of SFAS No. 143 in 2003.

      Production costs. In 2003, we experienced lower production costs primarily due to the asset sales discussed above. However, we also incurred higher production taxes in 2003 as a result of higher natural gas

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and oil prices and larger tax credits taken in 2002 on high cost natural gas wells. Our cost per unit increased due to the higher production taxes and lower production volumes.

      Ceiling test and other charges. In 2003, we incurred an impairment charge related to non-full cost pool assets of $5 million, net of gains on asset sales, non-cash ceiling test charges of $5 million associated with our operations in Brazil and $6 million in employee severance costs. In 2002, we incurred a non-cash ceiling test charge of $3 million associated with our operations in Brazil.

      General and administrative expenses. Higher corporate overhead allocations and lower capitalized costs were the main factors leading to the increase in general and administrative expenses in 2003. The cost per unit increased due to a combination of higher costs and lower production volumes discussed above.

Outlook for 2005

Based on our strategy to develop a more balanced portfolio of natural gas and oil production and allocate more capital to longer life, slower decline projects and development projects in longer reserve life areas, we anticipate in 2005:

•  A total capital expenditure budget, including acquisitions, of approximately $900 million.

•  Daily production volumes to average in excess of 800 MMcfe/d.

•  A focus on cost control, operating efficiencies, and process improvements to keep our per unit cash operating costs between $1.25/ MMcfe and $1.40/ MMcfe.

•  Industry-wide increases in drilling costs and oilfield service costs that will require constant monitoring of capital spending programs.

Non-regulated Business — Marketing and Trading Segment

Our Marketing and Trading segment’s operations focus on the marketing of our natural gas and oil production and the management of our remaining trading portfolio. Over the past several years, a number of significant events occurred in this business and in the industry:

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.

Currently, we do not anticipate that we will liquidate all of the transactions in our trading portfolio before the end of their contract term. We may retain contracts because (i) they are either uneconomical to sell or terminate in the current environment due to their contractual terms or credit concerns of the counterparty, (ii) a sale would require an acceleration of cash demands, or (iii) they represent hedges associated with activities reflected in other segments of our business, including our Production and Power segments. Changes to our liquidation strategy may impact the cash flows and the financial results of this segment.

      Our Marketing and Trading segment’s portfolio includes both contracts with third parties and contracts with affiliates that require physical delivery of a commodity or financial settlement. The following is a

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discussion of the significant types of contracts used by our Marketing and Trading segment and how they impact our financial results:

Natural Gas Contracts

     Production-related and other natural gas derivatives

   Derivatives designated as hedges. We enter into contracts with third parties, primarily fixed for floating swaps, on behalf of our Production segment to hedge its anticipated natural gas production. These natural gas contracts consist of obligations to deliver natural gas at fixed prices. As of December 31, 2004, these contracts effectively hedged a total of 244 TBtu of our anticipated natural gas production through 2012. Of this total amount, 84 percent of these contracts were designated as accounting hedges on December 1, 2004. All contracts that are designated as hedges of our Production segment’s natural gas and oil production are accounted for in the operating results of that segment.

   Production-related options. These contracts, which are marked to market in our results each period, and are not accounting hedges, provide price protection to El Paso from natural gas price declines related to our natural gas production in 2005 and 2006. Entered into in the fourth quarter of 2004, these contracts will allow El Paso to achieve a floor price of $6.00 per MMBtu on 60 TBtu of our natural gas production in 2005 and 120 TBtu in 2006.

   In the first quarter of 2005, we entered into additional contracts that provide El Paso with a floor price of $6.00 per MMBtu on 30 TBtu of our natural gas production in 2007, and also capped us at a ceiling price of $9.50 per MMBtu on 60 TBtu of our natural gas production in 2006.

   Other natural gas derivatives. Other natural gas derivatives consist of physical and financial natural gas contracts that impact our earnings as the fair values 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, overall, we purchase more or less natural gas than we sell under these contracts.

     Transportation-related contracts

      Our transportation contracts provide us with approximately 1.5 Bcf of pipeline capacity per day, for which we are charged approximately $149 million in annual demand charges. These contracts are accrual-based contracts that impact our gross margin as delivery or service under the contracts occurs. The following table details our transportation 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

      Historically, these contracts have resulted in significant losses to El Paso. The extent of these losses is dependent upon our ability to utilize the contracted pipeline capacity, which is impacted by:

•  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.

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     Storage contracts

      During 2003, we eliminated a significant portion of our natural gas storage capacity contracts through the ongoing liquidation of our trading portfolio. We retained storage capacity of 4.7 Bcf at TGP’s Bear Creek Storage Field and Enterprise Products Partners’ Wilson storage facilities for operational and balancing purposes. We do not anticipate that our retained storage contracts will significantly impact our earnings in the future.

Power Contracts

   Tolling contracts. We have two tolling contracts under which we supply fuel to power plants and receive the power generated by these plants. In exchange for this right to the power generated, we pay a demand charge. Our ability to recover these demand charges is primarily dependent upon the difference between the cost of fuel we supply to the plant and the value of the power we receive from the plant under the contract. Our tolling contracts are derivatives that impact our earnings as their fair value changes each period.

      Our largest tolling contract provides us with approximately 548 MW of generating capacity at the Cordova power plant through 2019, for which we are charged $27 million to $32 million in annual demand charges. In addition, the Cordova power plant has the option to repurchase up to 50 percent of this generating capacity from us. We have historically experienced significant volatility in the fair value of this tolling contract, primarily due to changes in natural gas and power prices in the market that Cordova serves. We expect this volatility to continue. Our other tolling contract provides us with approximately 257 MW of generating capacity in the Alberta power pool through the third quarter of 2005, for which we expect to be charged $14 million of demand charges in 2005.

   Contracts related to power restructuring activities. These contracts consist of long-term obligations to provide power for the restructured power contracts in our Power segment. With the sale of substantially all of our restructured power contracts, we have or are in the process of eliminating substantially all of these obligations, with the exception of our contract with Morgan Stanley related to UCF. This contract, which calls for us to deliver of up to 1,700 MMWh per year through 2016 at a fixed price, may continue to impact our earnings in the future.

Operating Results

      Below are the overall operating results and analysis of these results for our Marketing and Trading segment for each of the three years ended December 31. Because of the substantial changes in the composition of our portfolio, year-to-year comparability was affected:

			2004			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			15			10			16
		EBIT	$	(547	)	$	(809	)	$	(1,977	)

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				2004			2003			2002
				(In millions)
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.

     Overall, during 2004, 2003 and 2002, we experienced substantial losses in gross margin on our trading contracts due to a number of factors. In 2002, we experienced losses in our natural gas and power contracts as a result of general market declines in energy trading resulting from lower price volatility in the natural gas and power markets and a generally weaker trading and credit environment. Also contributing to the deterioration of the market valuations of our trading and marketing assets was the announcement in the fourth quarter of 2002 by many participants in the trading industry, including us, to discontinue or significantly reduce trading operations. Following this announcement, we liquidated a number of positions earlier than their scheduled maturity, which caused us to incur additional losses in gross margin in 2002 and 2003 than had we held those contracts to maturity. We also experienced difficulty in 2002 and 2003 in collecting on several claims from various industry participants experiencing financial difficulty, several of whom sought bankruptcy protection. Any settlements under ongoing proceedings in these matters could impact our future financial results.

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      Listed below is a discussion of other factors, by significant contract type, that affected the profitability of our Marketing and Trading segment during each of the three years ended December 31, 2004:

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.

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.

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Storage contracts

      In the fourth quarter of 2002, we began accounting for our storage 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. Our annual demand charges on these contracts were approximately $2 million in 2004 and $21 million in 2003. In 2002 and 2003, we terminated a significant number of our storage positions and recognized a $56 million gain in 2002 and a $31 million gain in 2003 on the withdrawal and sale of the gas held in these storage locations. Based on our actions, our remaining contracts with the Wilson and Bear Creek storage facilities should not have a significant impact on the future financial results of this segment.

Power Contracts

Cordova tolling agreement

      Our Cordova agreement is sensitive to changes in forecasted natural gas and power prices. In 2003, forecasted power prices increased relative to natural gas prices, resulting in a significant increase in the fair value of this contract. In 2004, forecasted natural gas prices increased relative to power prices, resulting in a decrease in the fair value of the contract. Additionally, although the Cordova power plant historically sold its power into a relatively illiquid power market in the Midwest, this power market was incorporated into the more liquid Pennsylvania-New Jersey-Maryland power pool in 2004. We believe that this change will reduce the volatility of the fair value of the contract in the future.

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 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.

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Operating Expenses

      Operating expenses in our Marketing and Trading segment decreased significantly each year due primarily to the following:

•  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.

Non-regulated Business — Power Segment

      As of December 31, 2004, our power segment primarily consisted of an international power business. Historically, this segment also included domestic power plant operations and a domestic power contract restructuring business. We have sold or announced the sale of substantially all of these domestic businesses. Our ongoing focus within the power segment will be to maximize the value of our assets in Brazil. We have designated our other international power operations as non-core activities, and expect to exit these activities in the future as market conditions warrant.

International Power Plant Operations

Brazil. As of December 31, 2004, our Brazilian operations include our Macae, Porto Velho, Manaus, Rio Negro, and Araucaria power plants and our investments in the Bolivia to Brazil and Argentina to Chile pipelines.

•  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 Part II, Item 8, Financial Statements and Supplementary Data, Note 17. 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 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 Part II, Item 8, Financial Statements and Supplementary Data, Note 17.

•  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

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	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 Part II, Item 8, Financial Statements and Supplementary Data, Note 17.

      Our two pipelines began operations in 2003 and generate income through the transportation of natural gas to various customers in South America.

Asia. Our Asian operations include interests in 15 power plants, 13 of which are equity investments. These facilities sell electricity and electrical generating capacity under long-term power sales agreements with local transmission and distribution companies, many of which are government controlled. The majority of these contracts allow for changes in fuel costs to be passed through to the customer through power prices. The economic performance of these facilities is impacted by the level of electricity demand and changes in the political and regulatory environment in the countries they serve as well as the relative cost of producing that power. We recorded an impairment of these assets in 2004 in connection with our decision to sell these assets.

Other International. We have interests in 10 power facilities located in South and Central America and Europe, most of which are equity investments. These facilities sell electricity and electrical generating capacity under long-term and short-term power sales agreements with local transmission and distribution companies as well as to the local spot markets. The economic performance of these facilities is impacted by fuel prices, the level of demand for electricity, the level of competition from other power generators, changes in the political and regulatory environment in the countries they serve, and the relative cost of producing power. The performance of our facilities in Central America is also affected by variances in the level of rainfall in the region. As the level of rainfall increases, the level of generation from hydroelectric plants increases which can negatively impact power pricing in the spot market. We have recently announced that we are considering the sale of a number of these assets, although at this time we have not actively marketed them. As this process progresses we will continue to assess the value of these assets which may result in impairments.

Domestic Power Plant Operations

      Our domestic operations as of December 31, 2004, primarily consist of an equity ownership in a natural gas-fired power plant, Midland Cogeneration Venture (MCV). The price of electricity sold by MCV is indexed to coal, while the plant is fueled by natural gas, which it purchases under both long-term contracts and on the spot market. Changes in the relationship between coal and natural gas prices directly impact the economic performance of this facility. In 2004, we recorded an impairment of our interest in this plant based on a decline in the value of the investment that we considered to be other than temporary.

      During 2004 and the first quarter of 2005, we sold our interests in 33 domestic power plants. With these sales, we incurred substantial impairments in 2003 and 2004. As a result of these sales, we will have substantially lower earnings in our Power segment.

Domestic Power Contract Restructuring Business

      In 2002 and 2003, we maintained or completed several contract restructuring transactions, the largest of which was UCF. During 2004, we completed the sale of UCF and its related restructured power contract, and entered into an agreement to sell our ownership in Cedar Brakes I and II, and their related restructured power contracts. As of December 31, 2004, we held an interest in Mohawk River Funding II and Cedar Brakes I and

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II. We completed the sale of Cedar Brakes I and II in the first quarter of 2005 and are evaluating potential buyers for Mohawk River Funding II.

Operating Results

Below are the overall operating results and analysis of activities within our Power segment for each of the three years ended December 31. Substantial changes in the business during these periods affected year-to-year comparability.

				2004			2003			2002
				(In millions)
Overall EBIT:
	Gross margin(1)			$	643		$	865		$	1,103
	Operating expenses
		Loss on long-lived assets			(583	)		(185	)		(160	)
		Other operating expenses			(468	)		(693	)		(591	)
			Operating income (loss)		(408	)		(13	)		352
	Earnings from unconsolidated affiliates
		Impairments and net losses on sale			(390	)		(347	)		(426	)
		Equity in earnings			154			256			170
	Other income (expense)				75			76			(84	)
		EBIT		$	(569	)	$	(28	)	$	12
EBIT by Area:
	International power
		Brazilian operations		$	69		$	177		$	78
		Asian operations			(140	)		49			(3	)
		Other			12			70			(243	)
					(59	)		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		$	(569	)	$	(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.
(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.

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International Power. The following table shows significant factors impacting EBIT in our international power business in 2004, 2003 and 2002:

				2004			2003		2002
				(In millions)
Brazil
	Earnings from consolidated and unconsolidated plant operations			$	236		$	177	$	97
	Manaus and Rio Negro impairment				(167	)		—		—
	Contract termination fee				—			—		(19	)
		Total Brazil			69			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				11			—		—
		Total Asia			(140	)		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				(9	)		—		—
		Total Other			12			70		(243	)
			Total	$	(59	)	$	296	$	(168	)

Brazil. During 2002 and 2003, we completed the construction of several power plants and pipelines, which allowed them to reach full operational capacity. However, our financial results during each of the three years ended December 31, 2004 were impacted significantly by regional economic and political conditions, which affected the renegotiation of several of the power contracts for our Brazilian power plants. Below is a discussion of each of our significant assets in Brazil.

                    Macae and Porto Velho

      Through the first quarter of 2003, we conducted a majority of our power plant operations in Brazil through Gemstone, an unconsolidated joint venture. In April 2003, we acquired the joint venture partner’s interest in Gemstone and began consolidating Gemstone’s debt and its interests in the Macae and Porto Velho power plants. As a result, our operating results for 2002 and the first quarter of 2003 include the equity earnings we earned from Gemstone, while our consolidated operating results for all other periods in 2003 and 2004 include the revenues, expenses and equity earnings from Gemstone’s assets.

      The EBIT we earned from our Macae plant’s operations was $172 million, $156 million, and $136 million in 2004, 2003, and 2002. The increase in 2003 was primarily due to Macae reaching full operational capacity in the third quarter of 2002. In addition, the consolidation of Gemstone described above improved our EBIT in 2003 and 2004 since the interest and taxes incurred by Gemstone were no longer included in EBIT.

      The EBIT we earned from our Porto Velho plant’s operations was $28 million, $28 million and $23 million in 2004, 2003, and 2002. The increase in 2003 was primarily due to Porto Velho reaching full operational capacity in mid-2003. In the fourth quarter of 2004, our Porto Velho plant

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experienced an equipment failure that is expected to temporarily reduce the output of the plant by approximately 30 percent. This equipment failure is expected to be repaired by the first quarter of 2006.

      Our combined net exposure on the Macae and Porto Velho plants was approximately $0.8 billion at December 31, 2004. We are currently in negotiations over the Porto Velho contracts with Eletronorte and in a dispute with Petrobras over the Macae contract. As these negotiations and disputes progress, it is possible that impairments of these assets may occur, and these impairments may be significant. For a further discussion of these negotiations and disputes, see Part II, Item, 8, Financial Statements and Supplementary Data, Note 17.

                    Manaus and Rio Negro

      In 2003, we began negotiating the extension of the Manaus and Rio Negro power contracts, which were to expire in 2005 and 2006. Based on the status of our negotiations to extend the contracts, which was negatively impacted by changes in the Brazilian political environment in 2004, we recorded a $167 million impairment of our investment in Manaus and Rio Negro in 2004. We completed an extension of these contracts during the first quarter of 2005. The Manaus and Rio Negro plants had earnings from plant operations of $30 million in 2004, $12 million in 2003 and $18 million in 2002.

                    South American Pipelines

      The EBIT for our Brazilian operations includes EBIT earned by our Bolivia to Brazil and Argentina to Chile pipelines. This amount was $28 million in 2004 and $18 million in 2003. Our EBIT earned by these pipelines was not significant in 2002. Increases during the three year period were primarily due to the Bolivia to Brazil pipeline reaching full operational capacity in the third quarter of 2003.

Asia. During the fourth quarter of 2004, we recorded a $212 million charge on our Asian power assets in connection with our decision to pursue the sale of these assets. These impairment amounts were based on our estimates of the fair value of these projects. In 2005, we engaged a financial advisor to assist us in the sale of these assets. In the first quarter of 2005, we sold our investment in the PPN power facility in India for $20 million. We had impaired this plant in 2002 primarily because of regional political and economic events at that time. As the sales process continues, we will continue to update the fair value of our Asian assets, which may result in further impairments.

      From 2002 to 2004, earnings from our Asian power assets were relatively stable as the underlying plants maintained steady levels of availability and production. Higher fuel costs during these periods did not materially impact these plants’ operations as substantially all of the higher fuel costs were passed through to the power purchasers through higher contracted power prices.

      However, during this three year period, several other significant events occurred that improved our financial performance from these assets, including:

•  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.

Other International. The earnings from our other international operations have decreased from 2002 to 2004 due primarily to economic difficulties in some of the countries that we serve as well as specific

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transactions that affected the profitability of the underlying plants. Major factors contributing to the decreases were:

•  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 Part II, Item 8, Financial Statements and Supplementary Data, Note 22 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.

      As part of our long term business strategy, we are considering the sale of a number of our other international power assets. As these sales occur and/or as market indicators of fair value become available, it is possible that impairments of these assets may occur, and these impairments may be significant.

Domestic Power. The following table shows significant factors impacting EBIT within our domestic power business in 2004, 2003, and 2002:

			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.

MCV. Our MCV power plant is a natural gas-fired plant, which sells its power at a contracted price that is indexed to coal prices. During 2004, MCV experienced reduced EBIT primarily because natural gas prices increased at a faster rate than coal prices. This decrease in EBIT was magnified by an increase in the volume of power MCV was required to generate. In January 2005, MCV received regulatory approval to reduce the required level of power generation. In the fourth quarter of 2004, we impaired our investment in MCV based on a decline in the value of the investment due to increased

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fuel costs. We will continue to assess our ability to recover our investment in MCV and its related operations in the future.

Assets sold or to be sold in 2005. During the three years ended December 31, 2004, we recorded significant impairments in our domestic power business as discussed below.

•  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 Part II, Item 8, Financial Statements and Supplementary Data, Notes 2, 3, and 22 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.

Domestic Power Contract Restructuring. The following table shows significant factors impacting EBIT within our domestic power contract restructuring activities in 2004, 2003 and 2002:

			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

      In 2002, we restructured several above-market, long-term power sales contracts with regulated utilities that were originally tied to older power plants. These contracts were amended so that the power sold to the utilities was not required to be delivered from the specified power generation plant, but could be obtained in the wholesale power market. As a result of our credit rating downgrades and economic changes in the power market, we are no longer pursuing additional power contract restructuring activities and are exiting such activities which will reduce our EBIT in future periods. For a further discussion of our power restructuring activities, see below and Part II, Item 8, Financial Statements and Supplementary Data, Note 10.

Restructuring Gain. During 2002, we restructured the power sales contracts at our Eagle Point power facility (also known as UCF) and our Mount Carmel power plant, which resulted in combined net gains of $501 million (net of minority interest.) Prior to restructuring the contracts, the power plants’ power purchase contracts were accounted for using accrual accounting. Following the restructuring, the power purchase agreements were accounted for as derivatives and recorded at fair value, resulting in a net gain on the date the contracts were restructured. In conjunction with the UCF restructuring in 2002, we paid a

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$90 million contract termination fee to terminate a steam contract between our Eagle Point power plant and the Eagle Point refinery and we recorded an $80 million loss on a power supply agreement that we entered into with our Marketing and Trading segment. The $90 million and $80 million losses eliminated in El Paso’s consolidated results.

Sale of UCF/ Cedar Brakes I and II. During 2004, we sold UCF and in March 2005 we sold Cedar Brakes I and II. These sales resulted in impairments on the Cedar Brakes I and II entities and on UCF in 2004.

Non-regulated Business — Field Services Segment

      Our Field Services segment conducts our remaining midstream activities, which primarily include gathering and processing assets in south Louisiana. During 2002, 2003 and 2004, we held significant general and limited partner interests in GulfTerra and Enterprise. From December 2003 to January 2005, we sold all of our general and limited partner interests in GulfTerra and Enterprise, our South Texas processing plants, and our interests in the Indian Springs natural gas gathering and processing assets to Enterprise in a series of transactions described further in Part II, Item 8, Financial Statements and Supplementary Data, Note 22.

      During 2003 and 2004, the primary source of earnings in our Field Services segment was from our interests in GulfTerra and Enterprise. On the sale of our interests in GulfTerra in 2003 and 2004, we recognized significant gains, as well as a goodwill impairment of $480 million. Prior to the sale of our interests in GulfTerra, we also received management fees under an agreement to provide operational and administrative services to the partnership. In addition, we received reimbursements for costs paid directly by us on GulfTerra’s behalf. For the twelve months ended December 31, 2004, 2003, and 2002, we received approximately $71 million, $91 million, and $60 million in management fees and cost reimbursements. As a result of the sale of our general and limited partnership interests in September 2004, we no longer receive management fees and, as the result of the sale of our remaining interest in January 2005, we will no longer recognize equity earnings related to these investments.

      Our significant remaining obligations to Enterprise are to provide an estimated $45 million in payments to Enterprise during the next three years and provide for the reimbursement of a portion of Enterprise’s future pipeline integrity costs related to assets sold by us to GulfTerra in 2002 for which we recorded a $74 million liability in 2003. As a result of regulatory changes relating to pipeline integrity and subsequent negotiations with Enterprise, we reduced our estimated obligation to Enterprise by approximately $9 million during the fourth quarter of 2004. In addition, we are to provide for the reimbursement of a portion of GulfTerra’s maintenance expenses on certain previously sold assets for which we recorded an estimated liability and a charge to operating expenses of $8 million in 2004. For further discussion of these indemnification agreements, see Part II, Item 8, Financial Statements and Supplementary Data, Note 17.

      During 2004, our earnings and cash distributions received from GulfTerra and Enterprise were as follows:

	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

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      Below are the operating results and analysis of the results for our Field Services segment for each of the three years ended December 31:

			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.

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     Below is a summary of significant factors and related discussions affecting EBIT for each of the three years ended December 31:

			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

      Gathering and Processing Activities. During the three years ended December 31, 2004, we have experienced a decrease in our gross margin with a corresponding decrease in our operation and maintenance expenses primarily as a result of asset sales. Additionally, our gathering and processing margins during these periods have been impacted by the spread between NGL prices and natural gas prices. As these spreads increase, we generally increase the NGL volumes we extract, which affects our margin. In 2003, our margins were negatively impacted by a decrease in these spreads as natural gas prices relative to NGL prices increased, which also caused us to reduce the amount of NGL extracted as compared to 2002. However, in 2004 these margins were positively impacted by an increase in these spreads as NGL prices recovered, which also caused us to increase the amount of NGL extracted by our natural gas processing facilities in south Texas. In addition, our margin attributable to the marketing of NGL increased in 2004 as a result of lower fuel and transportation costs. In the future, the margins for our remaining assets will remain sensitive to the spread between natural gas pricing and NGL pricing.

      GulfTerra/ Enterprise Related Items. During 2002 and 2003, we sold a substantial amount of our assets to GulfTerra which decreased our gross margin and operating expenses, while at the same time increasing our equity earnings from our general and limited partner interests in GulfTerra. Listed below are the significant transactions with GulfTerra:

•  2002 — the gain on our sale of our Texas and New Mexico gathering and pipeline assets and our San Juan gathering assets.

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•  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.

      From December 2003 to January 2005, we entered into a series of transactions with Enterprise in which we sold all of our interests in GulfTerra. In December 2003, we sold 50 percent of our interest in GulfTerra to Enterprise and recorded a gain on the sale in other income. At the same time, we recorded an impairment of our south Texas assets in operating expenses based on the planned sale of these assets to Enterprise in 2004. In September 2004, we completed the sale of our remaining 50 percent interest in the general partner of GulfTerra to Enterprise and recorded a gain on the sale in other income. As a result of the substantial reduction in our asset base primarily from these sales to Enterprise, we recorded an impairment in operating expenses for the entire amount of goodwill upon determination that the goodwill in this segment was no longer recoverable. Finally, at the end of 2004, we entered into negotiations to sell our Indian Springs assets to Enterprise and recorded an impairment charge in operating expenses on these assets based on their planned sale in 2005. We completed the sale of the Indian Springs assets in January 2005. We also sold our remaining general and limited partnership interests in Enterprise for $425 million in January 2005.

      Other Asset Sales. In 2002, we recorded an impairment in operating expenses for our north Louisiana assets based on their planned sale, which was completed in 2003. In 2003, we recorded an impairment in other income of our investment in our Dauphin Island Gathering system and Mobile Bay Processing plant based on the planned sale of these investments. We sold these investments in August 2004.

Corporate and Other Expenses, Net

      Our corporate operations include our general and administrative functions as well as a telecommunications business, petroleum ship charter operations and various other contracts and assets, including financial services and LNG and related items, all of which are immaterial to our results. The following table presents items impacting the EBIT in our corporate operations for the years ended December 31:

		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			(3	)		(47	)		(12	)
Total EBIT		$	(214	)	$	(852	)	$	(387	)

      We have a number of pending litigation matters, including shareholder and other lawsuits filed against us. During 2004, we incurred additional legal costs related to changes in our estimated reserves for these existing legal matters. These changes were based on ongoing assessments, developments and evaluations of the possible outcomes of these matters. We also incurred accretion expense related to our Western Energy Settlement. Our Western Energy Settlement accrual assumes that we will make payments to claimants through 2023. If we retire this obligation earlier than that period, we could incur additional charges. Finally, in 2004, we increased our insurance reserves by approximately $30 million. This accrual related to our decision to withdraw from a mutual insurance company in which we were a member and an accrual for additional

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premiums in another. In all of our legal and insurance matters, we evaluate each suit and claim as to its merits and our defenses. Adverse rulings against us and/or unfavorable settlements related to these and other legal matters would impact our future results.

      As discussed in Part II, Item 8, Financial Statements and Supplementary Information, Note 4, we accrued $80 million in 2004 related to the consolidation of our Houston-based operations. Our estimated relocation costs are based on a discounted liability, which includes estimates of future sublease rentals. Our earnings in future periods will be impacted by the extent to which actual sublease rentals differ from our estimates, and by accretion of this discounted liability, which is estimated to be approximately $8 million for 2005. In total, had estimates of sublease rentals for vacated space that was not subleased as of December 31, 2004 been excluded from our calculations, our discounted liability would have been approximately $121 million versus the amount we recorded. For 2005, if we are unable to collect the estimated sublease rentals included in our accrual, we could incur an additional $3 million in rental expense. We are also pursuing the sale of our telecommunications facility in Chicago. As the sales process progresses we will continue to assess the value of this facility which may result in an impairment.

Interest and Debt Expense

      Below is an analysis of our interest and debt expense for each of the three years ended December 31 (in millions):

		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

      During 2004, our total interest and debt expense decreased primarily due to the retirements of long-term debt and other financing obligations (net of issuances) during 2003 and 2004. During 2004, we also paid off $850 million of borrowings under our previous $3 billion revolving credit facility. However, these repayments were offset by $1.25 billion borrowed under the new $3 billion credit agreement entered into in November 2004 and related charges and fees incurred with entering into the new credit agreement.

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

      During 2003, total interest and debt expense increased compared with 2002 as we issued additional debt securities and consolidated various financing obligations including those associated with Chaparral, Gemstone, Lakeside. We also reclassified certain of our preferred securities as long-term debt. Finally, interest expense on revolving credit facilities increased in 2003 from additional borrowings in 2003 as compared to 2002.

Distributions on Preferred Interests of Consolidated Subsidiaries

      Our distributions on preferred securities decreased significantly between 2002 and 2004. During this period, we redeemed a number of obligations including those related to our Clydesdale, Trinity River, and Coastal Securities financing arrangements. We also reclassified our Coastal Finance I and Capital Trust I mandatorily redeemable securities to long-term debt upon the adoption of SFAS No. 150 in 2003, and began recording the distributions on these securities as interest expense. Our remaining preferred interests at December 31, 2004 consists of $300 million of 8.25% preferred stock of our consolidated subsidiary, El Paso Tennessee Pipeline Co.

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For a further discussion of our borrowings and other financing activities related to our consolidated subsidiaries, see Part II, Item 8, Financial Statements and Supplementary Data, Notes 15 and 16.

Income Taxes

      Income taxes for the years ended December 31, 2004, 2003 and 2002 were $25 million, ($551) million and ($641) million resulting in effective tax rates of (3) percent, 51 percent and 34 percent. Differences in our effective tax rates from the statutory tax rate of 35 percent were primarily a result of the following factors:

•  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.

      For a reconciliation of the statutory rate to our effective tax rate, as well as matters that could impact our future tax expense, see below and Part II, Item 8, Financial Statements and Supplementary Data, Note 7.

      For 2004, our overall effective tax rate on continuing operations was significantly different than the statutory rate due primarily to the GulfTerra transactions and the impairments of certain of our foreign investments. The sale of our interests in GulfTerra associated with the merger between GulfTerra and Enterprise in September 2004 resulted in a significant net taxable gain (compared to a lower book gain) and significant tax expense due to the non-deductibility of a significant portion of the goodwill written off as a result of the transaction. The impact of this non-deductible goodwill increased our tax expense in 2004 by approximately $139 million. See Part II, Item 8, Financial Statements and Supplementary Data, Note 22 for a further discussion of the merger and related transactions. Additionally, we received no U.S. federal income tax benefit on the impairment of certain of our foreign investments. The effective tax rate for 2004 absent these items would have been 32 percent.

      For 2003, our overall effective tax rate on continuing operations was significantly different than the statutory rate due primarily to $124 million of tax benefits related to abandonments and sales of certain of our foreign investments. The effective tax rate for 2003 absent these tax benefits would have been 40 percent.

      In 2004, Congress proposed but failed to enact legislation that would disallow deductions for certain settlements made to or on behalf of governmental entities. It is possible Congress will reintroduce similar legislation in 2005. If enacted, this tax legislation could impact the deductibility of the Western Energy Settlement and could result in a write-off of some or all of the associated tax benefits. In such an event, our tax expense would increase. Our total tax benefits related to the Western Energy Settlement were approximately $400 million as of December 31, 2004.

      In October 2004, the American Jobs Creation Act of 2004 was signed into law. This legislation creates, among other things, a temporary incentive for U.S. multinational companies to repatriate accumulated income earned outside the U.S. at an effective tax rate of 5.25%. The U.S. Treasury Department has not issued final guidelines for applying the repatriation provisions of the American Jobs Creation Act. We have not provided U.S. deferred taxes on foreign earnings where such earnings were intended to be indefinitely reinvested outside the U.S. We are currently evaluating whether we will repatriate any foreign earnings under the American Jobs Creation Act, and are evaluating the other provisions of this legislation, which may impact our taxes in the future.

      As part of our long-term business strategy, we anticipate that we will sell our Asian power investments. As further discussed Part II, in Item 8, Financial Statements and Supplementary Data, Note 7, we have not

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historically recorded United States deferred taxes on book versus tax basis differences in these investments because our historical intent was to indefinitely reinvest earnings from these projects outside the United States. In 2004, our intent on these assets changed such that we now intend to use the proceeds from the sale within the U.S. As a result, we recorded U.S. deferred tax liabilities for those instances where the book basis in our investment exceeded the tax basis in 2004. At this time, however, due to uncertainties as to the manner, timing and approval of the sale transactions, we have not recorded U.S. deferred tax assets for those instances where the tax basis in our investment exceeded the book basis, except in instances where we believe the realization of the asset is assured. As these uncertainties become known, we will record additional tax effects to reflect the ultimate sale transactions, the amounts of which could have a significant impact on our future recorded tax amounts and our effective tax rates in those periods.

      We have a number of pending IRS Audits and income tax contingencies that are in various stages of completion as further discussed in Part II, Item 8, Financial Statements and Supplementary Data, Note 7. We have provided reserves on these matters that are based on our best estimate of the ultimate outcome of each matter. As these audits are finalized and as these contingencies are resolved, we will adjust our estimates, the impact of which could have a material effect on the recorded amount of income taxes and our effective tax rates in those periods.

Discontinued Operations

      For the year ended December 2004, the loss from our discontinued operations was $146 million compared to a loss of $1,396 million during 2003. In 2004, $76 million of losses from discontinued operations related to our Canadian and certain other international production operations, primarily from losses on sales and impairment charges, and $70 million was from our petroleum markets activities, primarily related to losses on the completed sales of our Eagle Point and Aruba refineries along with other operational and severance costs. The losses in 2003 related primarily to impairment charges on our Aruba and Eagle Point refineries and on chemical assets, all as a result of our decision to exit and sell these businesses and ceiling test charges related to our Canadian production operations. The loss in 2002 was primarily due to operating losses at our Aruba refinery, impairment charges on our MTBE chemical plant and coal mining operations, and ceiling test charges related to our Canadian production operations.

Commitments and Contingencies

      For a discussion of our commitments and contingencies, see Part II, Item 8, Financial Statements and Supplementary Data, Note 17, incorporated herein by reference.

Critical Accounting Policies

      Our critical accounting policies are those accounting policies that involve the use of complicated processes, assumptions and/or judgments in the preparation of our financial statements. We have discussed the development and selection of our critical accounting policies and related disclosures with the audit committee of our Board of Directors and have identified the following critical accounting policies for the current year.

      Price Risk Management Activities. We record the derivative instruments used in our price risk management activities at their fair values in our balance sheet. We estimate the fair value of our derivative instruments using exchange prices, third-party pricing data and valuation techniques that incorporate specific contractual terms, statistical and simulation analysis and present value concepts. One of the primary assumptions used to estimate the fair value of our derivative instruments is pricing. Our pricing assumptions are based upon price curves derived from actual prices observed in the market, pricing information supplied by a third-party valuation specialist and independent pricing sources and models that rely on this forward pricing information. The table below presents the hypothetical sensitivity of our commodity-based price risk

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management activities to changes in fair values arising from immediate selected potential changes in quoted market prices:

				10 Percent Increase						10 Percent Decrease
	Fair Value			Fair Value			Change			Fair 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

      Other significant assumptions that we use in determining the fair value of our derivative instruments are those related to time value, anticipated market liquidity and credit risk of our counterparties. The assumptions and methodologies that we use to determine the fair values of our derivatives may differ from those used by our derivative counterparties. These differences can be significant and could impact our future operating results as we settle these derivative positions.

      Accounting for Natural Gas and Oil Producing Activities. Natural gas and oil reserves estimates underlie many of the accounting estimates in our financial statements as further discussed below. The process of estimating natural gas and oil reserves, particularly proved undeveloped and proved non-producing reserves, is very complex, requiring significant judgment in the evaluation of all available geological, geophysical, engineering and economic data. Accordingly, our reserve estimates are developed internally by a reserve reporting group separate from our operations group and reviewed by internal committees and internal auditors. In addition, a third party engineering firm which is appointed by, and reports to the Audit Committee of our Board of Directors prepares an independent estimate of a significant portion of our proved reserves. As of December 31, 2004, of our total proved reserves, 29 percent were undeveloped and 13 percent were developed, but non-producing. In addition, the data for a given field may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. In addition, the subjective decisions and variances in available data for various fields increases the likelihood of significant changes in these estimates.

      The estimates of proved natural gas and oil reserves primarily impact our property, plant and equipment amounts in our balance sheets and the depreciation, depletion and amortization amounts in our income statements, among other items. We use the full cost method to account for our natural gas and oil producing activities. Under this accounting method, we capitalize substantially all of the costs incurred in connection with the acquisition, development and exploration of natural gas and oil reserves in full cost pools maintained by geographic areas, regardless of whether reserves are actually discovered. We record depletion expense of these capitalized amounts over the life of our proved reserves based on the unit of production method and, if all other factors are held constant, a 10 percent increase in estimated proved reserves would decrease our unit of production depletion rate by 9 percent and a 10 percent decrease in estimated proved reserves would increase our unit of depletion rate by 11 percent.

      Under the full cost accounting method, we are required to conduct quarterly impairment tests of our capitalized costs in each of our full cost pools. This impairment test is referred to as a ceiling test. Our total capitalized costs, net of related income tax effects, are limited to a ceiling based on the present value of future net revenues from proved reserves using end of period spot prices and, discounted at 10 percent, plus the lower of cost or fair market value of unproved properties, net of related income tax effects. If these discounted revenues are not greater than or equal to the total capitalized costs, we are required to write-down our capitalized costs to this level. Our ceiling test calculations include the effect of derivative instruments we have designated as, and that qualify as hedges of our anticipated natural gas and oil production. As a result, higher proved reserves can reduce the likelihood of ceiling test impairments. We recorded ceiling test charges in our continuing and discontinued operations of $35 million, $76 million and $128 million during 2004, 2003 and 2002.

      The ceiling test calculation assumes that the price in effect on the last day of the quarter is held constant over the life of the reserves, even though actual prices of natural gas and oil are volatile and change from

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period to period. A decline in commodity prices can impact the results of our ceiling test and may result in writedowns. A decrease in commodity prices of 10 percent from the price levels at December 31, 2004 would not have resulted in a ceiling test charge in 2004.

      Asset Impairments. The asset impairment accounting rules require us to continually monitor our businesses and the business environment to determine if an event has occurred indicating that a long-lived asset or investment may be impaired. If an event occurs, which is a determination that involves judgment, we then assess the expected future cash flows against which to compare the carrying value of the asset group being evaluated, a process which also involves judgment. We ultimately arrive at the fair value of the asset which is determined through a combination of estimating the proceeds from the sale of the asset, less anticipated selling costs (if we intend to sell the asset), or the discounted estimated cash flows of the asset based on current and anticipated future market conditions (if we intend to hold the asset). The assessment of project level cash flows requires us to make projections and assumptions for many years into the future for pricing, demand, competition, operating costs, legal and regulatory issues and other factors and these variables can, and often do, differ from our estimates. These changes can have either a positive or negative impact on our impairment estimates. We recorded impairments of our long-lived assets of $1.1 billion, $791 million and $440 million during the years ended December 31, 2004, 2003 and 2002 and impairments on our unconsolidated affiliates of $397 million, $449 million, and $566 million during the years ended December 31, 2004, 2003 and 2002. We recorded impairments of our discontinued operations of $9 million, $1.5 billion and $290 million during the years ended December 31, 2004, 2003 and 2002. Future changes in the economic and business environment can impact our assessments of potential impairments.

      Accounting for Environmental Reserves. We accrue environmental reserves when our assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered, and an amount can be reasonably estimated. Estimates of our liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of societal and economic factors, and include estimates of associated onsite, offsite and groundwater technical studies, and legal costs. Actual results may differ from our estimates, and our estimates can be, and often are, revised in the future, either negatively or positively, depending upon actual outcomes or changes in expectations based on the facts surrounding each exposure.

      As of December 31, 2004, we had accrued approximately $380 million for environmental matters. Our reserve estimates range from approximately $380 million to approximately $547 million. Our accrual represents a combination of two estimation methodologies. First, where the most likely outcome can be reasonably estimated, that cost has been accrued ($82 million). Second, where the most likely outcome cannot be estimated, a range of costs is established ($298 million to $465 million) and the lower end of the range has been accrued.

      Accounting for Pension and Other Postretirement Benefits. As of December 31, 2004, we had a $956 million pension asset and a $274 million other postretirement benefit liability reflected in other assets and liabilities in our balance sheet related to our pension and other postretirement benefit plans. These amounts are primarily based on actuarial calculations. These calculations include assumptions, including those related to the return that we expect to earn on our plan assets, discount rates used in calculating benefit obligations, the rate at which we expect the compensation of our employees to increase over the plan term, the estimated cost of health care when benefits are provided under our plans and other factors.

      Actual results may differ from the assumptions included in these calculations, and as a result our estimates associated with our pension and other postretirement benefits can be, and often are, revised in the future. The income statement impact of the changes in the assumptions on our related benefit obligations are generally deferred and amortized into income over the life of the plans. The cumulative amount deferred as of December 31, 2004 is recorded as an $800 million increase in our pension asset and a $32 million reduction of our other postretirement liability. The following table shows the impact of a one percent change in the primary

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assumptions used in our actuarial calculations associated with our pension and other postretirement benefits for the year ended December 31, 2004 (in millions):

		Pension Benefits						Other Postretirement Benefits
					Projected						Accumulated
		Net Benefit			Benefit			Net Benefit			Postretirement
		Expense (Income)			Obligation			Expense (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.

     Our discount rate assumptions reflect the rates of return on the investments we expect to use to settle our pension and other postretirement obligations in the future. We combined current and expected rates of return on investment grade corporate bonds to develop the discount rates used in our benefit expense and obligation estimates as of September 30, 2004.

      Our estimates for our net benefit expense (income) are partially based on the expected return on pension plan assets. We use a market-related value of plan assets to determine the expected return on pension plan assets. In determining the market-related value of plan assets, differences between expected and actual asset returns are deferred and recognized over three years. If we used the fair value of our plan assets instead of the market-related value of plan assets in determining the expected return on pension plan assets, our net benefit expense would have been $14 million higher for the year ended December 31, 2004.

      We have not recorded an additional pension liability for our primary pension plan because the fair value of assets of that plan exceeded the accumulated benefit obligation of that plan by approximately $262 million and $366 million as of September 30, 2004 and December 31, 2004. If the accumulated benefit obligation exceeded plan assets under this primary pension plan as of September 30, 2004, we would have recorded a pre-tax additional pension liability of approximately $960 million, plus an amount equal to the excess of the accumulated benefit obligation over plan assets of that plan. We would have also recorded an amount equal to this additional pension liability to accumulated other comprehensive loss, net of taxes, in our balance sheet.

New Accounting Pronouncements Issued But Not Yet Adopted

      See Part II, Item 8, Financial Statements and Supplementary Data, Note 1 under New Accounting Pronouncements Issued But Not Yet Adopted which is incorporated herein by reference.

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RISK FACTORS AND CAUTIONARY STATEMENT FOR PURPOSES OF THE “SAFE HARBOR”

PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

      This report contains or incorporates by reference forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Where any forward-looking statement includes a statement of the assumptions or bases underlying the forward-looking statement, we caution that, while we believe these assumptions or bases to be reasonable and in good faith, assumed facts or bases almost always vary from the actual results, and differences between assumed facts or bases and actual results can be material, depending upon the circumstances. Where, in any forward-looking statement, we or our management express an expectation or belief as to future results, that expectation or belief is expressed in good faith and is believed to have a reasonable basis. We cannot assure you, however, that the statement of expectation or belief will result or be achieved or accomplished. The words “believe,” “expect,” “estimate,” “anticipate” and similar expressions will generally identify forward-looking statements. All of our forward-looking statements, whether written or oral, are expressly qualified by these cautionary statements and any other cautionary statements that may accompany such forward-looking statements. In addition, we disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report.

      With this in mind, you should consider the risks discussed elsewhere in this report and other documents we file with the SEC from time to time and the following important factors that could cause actual results to differ materially from those expressed in any forward-looking statement made by us or on our behalf.

Risks Related to Our Business

Our operations are subject to operational hazards and uninsured risks.

      Our operations are subject to the inherent risks normally associated with those operations, including pipeline ruptures, explosions, pollution, release of toxic substances, fires and adverse weather conditions, and other hazards, each of which could result in damage to or destruction of our facilities or damages to persons and property. In addition, our operations face possible risks associated with acts of aggression on our domestic and foreign assets. If any of these events were to occur, we could suffer substantial losses.

      While we maintain insurance against many of these risks to the extent and in amounts that we believe are reasonable, our financial condition and operations could be adversely affected if a significant event occurs that is not fully covered by insurance.

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

      Most of the natural gas and natural gas liquids we transport and store are owned by third parties. As a result, the volume of natural gas and natural gas liquids involved in these activities depends on the actions of those third parties, and is beyond our control. Further, the following factors, most of which are beyond our control, may unfavorably impact our ability to maintain or increase current throughput, to renegotiate existing contracts as they expire, or to remarket unsubscribed capacity on our pipeline systems:

•  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;

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•  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.

      Substantially all of our pipeline subsidiaries’ revenues are generated under contracts which expire periodically and must be renegotiated and extended or replaced. We cannot assure that we will be able to extend or replace these contracts when they expire or that the terms of any renegotiated contracts will be as favorable as the existing contracts.

      In particular, our ability to extend and/or replace contracts could be adversely affected by factors we cannot control, including:

•  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.

      If we are unable to renew, extend or replace these contracts or if we renew them on less favorable terms, we may suffer a material reduction in our revenues, earnings and cash flows.

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

      Revenues generated by our transmission, storage, and processing contracts depend on volumes and rates, both of which can be affected by the prices of natural gas and natural gas liquids. Increased prices could result in a reduction of the volumes transported by our customers, such as power companies who, depending on the price of fuel, may not dispatch gas-fired power plants. Increased prices could also result from industrial plant shutdowns or load losses to competitive fuels as well as local distribution companies’ loss of customer base. We also experience earnings volatility when the amount of gas utilized in operations differs from amounts we receive for that purpose. The success of our transmission, storage and processing operations is subject to continued development of additional oil and natural gas reserves and our ability to access additional suppliers from interconnecting pipelines to offset the natural decline from existing wells connected to our systems. A decline in energy prices could precipitate a decrease in these development activities and could cause a decrease in the volume of reserves available for transmission, storage and processing through our systems or facilities. We retain a fixed percentage of natural gas transported for use as fuel and to replace lost and unaccounted for gas, and we are at risk for the difference between the retained amount and actual gas consumed or lost and unaccounted. Pricing volatility may also impact the value of under or over recoveries of this retained gas. If natural gas prices in the supply basins connected to our pipeline systems are higher on a delivered basis to our off-system markets than delivered prices from other natural gas producing regions, our

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ability to compete with other transporters may be negatively impacted. Fluctuations in energy prices are caused by a number of factors, including:

•  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.

      Our future financial condition, revenues, results of operations, cash flows and future rate of growth depend primarily upon the prices we receive for our natural gas and oil production. Natural gas and oil prices historically have been volatile and are likely to continue to be volatile in the future, especially given current world geopolitical conditions. The prices for natural gas and oil are subject to a variety of additional factors that are beyond our control. These factors include:

•  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.

      Further, because approximately 82 percent of our proved reserves at December 31, 2004 were natural gas reserves, we are substantially more sensitive to changes in natural gas prices than we are to changes in oil prices. Declines in natural gas and oil prices would not only reduce revenue, but could reduce the amount of natural gas and oil that we can produce economically and, as a result, could adversely affect the financial results of our production business. Changes in natural gas and oil prices can have a significant impact on the calculation of our full cost ceiling test. A significant decline in natural gas and oil prices could result in a downward revision of our reserves and a write-down of the carrying value of our natural gas and oil properties, which could be substantial, and would negatively impact our net income and stockholders’ equity.

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

      In addition to prices, the performance of our natural gas and oil exploration and production businesses is dependent, in part, upon a number of factors that we cannot control, including:

•  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, 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;

•  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.

      Our operations are subject to all the risks normally incident to the operation and development of natural gas and oil properties and the drilling of natural gas and oil wells, including well blowouts, cratering and explosions, pipe failure, fires, formations with abnormal pressures, uncontrollable flows of natural gas, oil, brine or well fluids, release of contaminants into the environment and other environmental hazards and risks. The nature of the risks is such that some liabilities could exceed our insurance policy limits, or, as in the case of environmental fines and penalties, cannot be insured. As a result, we could incur substantial costs that could adversely affect our future results of operations, cash flows or financial condition.

      In addition, in our drilling operations we are subject to the risk that we will not encounter commercially productive reservoirs. New wells drilled by us may not be productive, or we may not recover all or any portion of our investment in those wells. Drilling for natural gas and oil can be unprofitable, not only because of dry holes but wells that are productive may not produce sufficient net reserves to return a profit at then realized prices after deducting drilling, operating and other costs.

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

      Estimating quantities of proved natural gas and oil reserves is a complex process that involves significant interpretations and assumptions. It requires interpretations of available technical data and various estimates, including estimates based upon assumptions relating to economic factors, such as future commodity prices, production costs, severance and excise taxes, capital expenditures and workover and remedial costs, and the assumed effect of governmental regulation. As a result, our reserve estimates are inherently imprecise. Also, the use of a 10 percent discount factor for estimating the value of our reserves, as prescribed by the SEC, may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our production business or the natural gas and oil industry, in general, are subject. Any significant variations from the interpretations or assumptions used in our estimates or changes of conditions could cause the estimated quantities and net present value of our reserves to differ materially.

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      Our reserve data represents an estimate. You should not assume that the present values referred to in this report represent the current market value of our estimated natural gas and oil reserves. The timing of the production and the expenses from development and production of natural gas and oil properties will affect both the timing of actual future net cash flows from our proved reserves and their present value. Changes in the present value of these reserves could cause a write-down in the carrying value of our natural gas and oil properties, which could be substantial, and would negatively affect our net income and stockholders’ equity.

      As of December 31, 2004, approximately 29 percent of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data assumes that we can and will make these expenditures and conduct these operations successfully, but future events, including commodity price changes, may cause these assumptions to change. In addition, estimates of proved undeveloped reserves and proved but non-producing reserves are subject to greater uncertainties than estimates of proved producing reserves.

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

      The success of our remaining domestic and international power projects could be adversely affected by factors beyond our control, including:

•  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;

•  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.

      Some of our subsidiaries use futures, swaps and option contracts traded on the New York Mercantile Exchange, over-the-counter options and price and basis swaps with other natural gas merchants and financial institutions. To the extent we have positions that are not designated or qualify as hedges, changes in commodity prices, interest rates, volatility, correlation factors, the liquidity of the market could cause our revenues, net income and cash requirements to be volatile.

      We could incur financial losses in the future as a result of volatility in the market values of the energy commodities we trade, or if one of our counterparties fails to perform under a contract. The valuation of these financial instruments involves estimates. Changes in the assumptions underlying these estimates can occur, changing our valuation of these instruments and potentially resulting in financial losses. To the extent we hedge our commodity price exposure and interest rate exposure, we forego the benefits we would otherwise experience if commodity prices were to increase, or interest rates were to change. The use of derivatives also requires the posting of cash collateral with our counterparties which can impact our working capital (current assets and liabilities) when commodity prices or interest rates change. For additional information concerning

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our derivative financial instruments, see Item 7A, Quantitative and Qualitative Disclosures About Market Risk and Part II, Item 8, Financial Statements and Supplementary Data, Note 10.

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

      We frequently extend credit to our counterparties following the performance of credit analysis. Despite performing this analysis, we are exposed to the risk that we may not be able to collect amounts owed to us. Although in many cases we have collateral to secure the counterparty’s performance, it could be inadequate and we could suffer credit losses.

Our foreign operations and investments involve special risks.

      Our activities in areas outside the United States, including material investment exposure in our power, pipeline and production projects in Brazil and Pakistan, are subject to the risks inherent in foreign operations, including:

•  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.

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

      We have sold a significant number of assets over the years, including the sale of many assets since 2001. Pursuant to various purchase and sale agreements relating to businesses and assets that we have divested, we have either retained certain liabilities or indemnified certain purchasers against liabilities that they might incur in the future. These liabilities in many cases relate to breaches of warranties, environmental, tax, litigation, personal injury and other representations that we have provided. Although we believe that we have established appropriate reserves for these liabilities, we could be required to accrue additional reserves in the future and these amounts could be material. In addition, as we exit businesses, we have experienced substantial reductions and turnover in our workforce that previously supported the ownership and operation of such assets. There is the risk that such reductions and turnover in our workforce could result in errors or mistakes in managing the businesses that we are exiting prior to closing. There is also the risk that such reductions could result in errors or mistakes in managing the retained liabilities after closing, including the lack of any historical knowledge with regard to such assets and businesses in managing the liabilities or defending any associated litigation.

Risks Related to Legal and Regulatory Matters

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

      In 2004, we restated our historical financial statements as a result of a downward revision of our natural gas and oil reserves and because of the manner in which we applied the accounting rules related to many of our historical hedges, primarily those associated with hedges of our anticipated natural gas production. As a result of this reduction in reserve estimates, several class action lawsuits were filed against us and several of our subsidiaries. The reserve revisions are also the subject of investigations by the SEC and the U.S. Attorney and the hedging matters are also the subject of an investigation by the U.S. Attorney and may become the subject of a separate inquiry by the SEC, any of which could result in significant fines against us. These investigations and lawsuits, and possible future claims based on these same facts, may further negatively impact our credit ratings and place further demands on our liquidity. We cannot provide assurance at this time

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that the effects and results of these or other investigations or of the class action lawsuits will not be material to our financial conditions, results of operations and liquidity.

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

      Our pipeline businesses are regulated by the FERC, the U.S. Department of Transportation, and various state and local regulatory agencies. Regulatory actions taken by those agencies have the potential to adversely affect our profitability. In particular, the FERC regulates the rates our pipelines are permitted to charge their customers for their services. In setting authorized rates of return in a few recent FERC decisions, the FERC has utilized a proxy group of companies that includes local distribution companies that are not faced with as much competition or risks as interstate pipelines. The inclusion of these companies creates downward pressure on approved tariff rates. If our pipelines’ tariff rates were reduced in a future proceeding, if our pipelines’ volume of business under their currently permitted rates was decreased significantly, or if our pipelines were required to substantially discount the rates for their services because of competition or because of regulatory pressure, the profitability of our pipeline businesses could be reduced.

      In addition, increased regulatory requirements relating to the integrity of our pipelines requires additional spending in order to maintain compliance with these requirements. Any additional requirements that are enacted could significantly increase the amount of these expenditures.

      Further, state agencies that regulate our pipelines’ local distribution company customers could impose requirements that could impact demand for our pipelines’ services.

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

      Our operations are subject to various environmental laws and regulations. These laws and regulations obligate us to install and maintain pollution controls and to clean up various sites at which regulated materials may have been disposed of or released. Some of these sites have been designated as Superfund sites by the EPA under the Comprehensive Environmental Response, Compensation and Liability Act. We are also party to legal proceedings involving environmental matters pending in various courts and agencies.

      Compliance with environmental laws and regulations can require significant costs, such as costs of clean-up and damages arising out of contaminated properties, and the failure to comply with environmental laws and regulations may result in fines and penalties being imposed. It is not possible for us to estimate reliably the amount and timing of all future expenditures related to environmental matters because of:

•  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.

      Although we believe we have established appropriate reserves for liabilities, including clean up costs, we could be required to set aside additional reserves in the future due to these uncertainties, and these amounts could be material. For additional information concerning our environmental matters, see Part I, Item 3, Legal Proceedings, and Part II, Item 8, Financial Statements and Supplementary Data, Note 17.

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

      We are involved in various lawsuits in which we or our subsidiaries have been sued. We also have other contingent liabilities and exposures. Although we believe we have established appropriate reserves for these liabilities, we could be required to set aside additional reserves in the future and these amounts could be

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material. For additional information concerning our litigation matters and other contingent liabilities, see Part I, Item 8, Financial Statements and Supplementary Data, Note 17.

                  Our system of internal controls ensure 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.

      Section 404 of the Sarbanes-Oxley Act of 2002, requires us to provide an annual report on our internal controls over financial reporting, including an assessment as to whether or not our internal controls over financial reporting are effective. We are also required to have our auditors attest to our assessment and to opine on the effectiveness of our internal controls over financial reporting. Based upon such review, we concluded that as of December 31, 2004 we did not maintain effective internal control over financial reporting. As more fully discussed in Item 9A, we identified several deficiencies in internal control over financial reporting that management has concluded constitute material weaknesses. Although we have taken steps to remediate some of these deficiencies, additional steps must be taken to remediate the remaining control deficiencies. If we are unable to remediate our identified internal control deficiencies over financial reporting by the end of 2005, or we identify additional deficiencies in our internal controls over financial reporting, we could be subjected to additional regulatory scrutiny, future delays in filing our financial statements and suffer a loss of public confidence in the reliability of our financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, which could have a negative impact on our liquidity, access to capital markets, financial condition and the market value of our common stock.

      In addition to the risk of not completing the remediation of all deficiencies in our internal controls over financial reporting, we do not expect that our disclosure controls and procedures or our internal controls over financial reporting will prevent all mistakes, errors and fraud. Any system of internal controls, no matter how well designed or implemented, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. The design of a control system must reflect the fact that the benefits of controls must be considered relative to their costs. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Therefore, any system of internal controls is subject to inherent limitations, including the possibility that controls may be circumvented or overridden, that judgments in decision-making can be faulty, and that misstatements due to mistakes, errors or fraud may occur and may not be detected. Also, while we document our assumptions and review financial disclosures with the Audit Committee of our Board of Directors, the regulations and literature governing our disclosures are complex and reasonable persons may disagree as to their application to a particular situation or set of facts. In addition, the applicable regulations and literature are relatively new. As a result, they are potentially subject to change in the future, which could include changes in the interpretation of the existing regulations and literature as well as the issuance of more detailed rules and procedures.

Risks Related to Our Liquidity

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 have significant debt of approximately $19 billion as of December 31, 2004 and have significant debt service and debt maturity obligations. The ratings assigned to our senior unsecured indebtedness are below investment grade, currently rated Caa1 by Moody’s Investor Service (Moody’s) and CCC+ by Standard & Poor’s. These ratings have increased our cost of capital and our operating costs, particularly in our trading operations, and could impede our access to capital markets. Moreover, we must retain greater liquidity levels to operate our business than if we had investment grade credit ratings. Our debt maturities as of December 31, 2004 for 2005, 2006 and 2007 are $948 million, $1,155 million and $835 million, respectively. If our ability to generate or access capital becomes significantly restrained, our financial condition and future results of operations could be significantly adversely affected. See Part II, Item 8, Financial Statements and Supplementary Data, Note 15, for a further discussion of our debt.

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

      Our ability to achieve the objectives of our Long-Range Plan, as well as the timing of their achievement, if at all, is subject, in part, to factors beyond our control. These factors include (1) our ability to raise cash from asset sales, which may be impacted by our ability to locate potential buyers in a timely fashion and obtain a reasonable price, (2) our ability to manage our working capital, (3) our ability to generate additional cash by improving the performance of our pipeline and production operations, (4) our ability to exit the power and trading businesses in the manner and within the time period we expect, (5) our ability to significantly reduce debt, and (6) our ability to preserve sufficient cash flow to service our debt and other obligations. If we fail to achieve in a timely manner the targets of our Long-Range Plan, our liquidity or financial position could be materially adversely affected. In addition, it is possible that any of the asset sales contemplated by our Long-Range Plan could be at prices that are below our current book value for the assets, which could result in losses that could be substantial.

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 debt and other financing obligations contain restrictive covenants and cross-acceleration provisions, which become more restrictive over time. A breach of any of these covenants could preclude us or our subsidiaries from issuing letters of credit and from borrowing under our $3 billion credit agreement, and could accelerate our long-term debt and other financing obligations and those of our subsidiaries. If this were to occur, we may not be able to repay such debt and other financing obligations upon such acceleration.

      Our $3 billion credit agreement is collateralized by our equity interests in TGP, ANR, EPNG, CIG, WIC, Southern Gas Storage Company and ANR Storage Company. A breach of the covenants under the $3 billion agreement could permit the lender to exercise their rights to the collateral, and we could be required to liquidate these interests.

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.

      In 2004, we restated our historical financial statements as a result of a downward revision of our natural gas and oil reserves and because of the manner in which we applied the accounting rules related to our hedges of our natural gas production and certain other derivatives. As a result of the time required to complete these revisions, our 2003 Form 10-K and our 2004 Forms 10-Q were not filed in a timely manner. As a result, until January 2006, our ability to access approximately $926 million of capacity under our existing shelf registration statement without filing additional disclosure information with the SEC is restricted. The additional disclosure requirements, and any related review by the SEC, could be expensive and impede our ability to access capital in a timely fashion. If our ability to access capital becomes significantly restrained, our financial condition and future results of operations could be significantly adversely affected.

We are subject to financing and interest rate exposure risks.

      Our future success depends on our ability to access capital markets and obtain financing at cost effective rates. Our ability to access financial markets and obtain cost-effective rates in the future are dependent on a number of factors, many of which we cannot control, including changes in:

•  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.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

      We are exposed to several market risks in our normal business activities. Market risk is the potential loss that may result from market changes associated with an existing or forecasted financial or commodity transaction. The types of market risks we are exposed to and examples of each are:

•  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.

      We manage these risks by frequently entering into contractual commitments involving physical or financial settlement that attempts to limit the amount of risk or opportunity related to future market movements. Our risk management activities typically involve the use of the following types of contracts:

•  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;

•  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.

      Many of the contracts we utilize in our risk management activities are derivative financial instruments. A discussion of our accounting policies for derivative instruments are included in Part II, Item 8, Financial Statements and Supplementary Data, Notes 1 and 10.

Commodity Price Risk

      We are exposed to a variety of commodity price risks in the normal course of our business activities. The nature of these market price risks varies by segment.

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     Marketing and Trading

      Our Marketing and Trading segment attempts to mitigate its exposure to commodity price risk through the use of various financial instruments, including forwards, swaps, options and futures. We measure risks from our Marketing and Trading segment’s commodity and energy-related contracts on a daily basis using a Value-at-Risk simulation. This simulation allows us to determine the maximum expected one-day unfavorable impact on the fair values of those contracts due to adverse market movements over a defined period of time within a specified confidence level, and monitors our risk in comparison to established thresholds. We use what is known as the historical simulation technique for measuring Value-at-Risk. This technique simulates potential outcomes in the value of our portfolio based on market-based price changes. Our exposure to changes in fundamental prices over the long-term can vary from the exposure using the one-day assumption in our Value-at-Risk simulations. We supplement our Value-at-Risk simulations with additional fundamental and market-based price analyses, including scenario analysis and stress testing to determine our portfolio’s sensitivity to its underlying risks.

      Our maximum expected one-day unfavorable impact on the fair values of our commodity and energy-related contracts as measured by Value-at-Risk based on a confidence level of 95 percent and a one-day holding period was $16 million and $34 million as of December 31, 2004 and 2003. Our highest, lowest and average of the month end values for Value-at-Risk during 2004 was $82 million, $16 million and $38 million. Actual losses in fair value may exceed those measured by Value-at-Risk. Our Value-at-Risk decreased during the fourth quarter of 2004 with the designation of a number of our natural gas derivative contracts as hedges of our Production segment’s natural gas production. The exposure of these derivatives to natural gas price fluctuations is now captured in the Production segment discussion below.

     Production

      Our Production segment attempts to mitigate commodity price risk and to stabilize cash flows associated with its forecasted sales of our natural gas and oil production through the use of derivative natural gas and oil swap contracts. The table below presents the hypothetical sensitivity to changes in fair values arising from immediate selected potential changes in the quoted market prices of the derivative commodity instruments we use to mitigate these market risks that were outstanding at December 31, 2004 and 2003. Any gain or loss on these derivative commodity instruments would be substantially offset by a corresponding gain or loss on the hedged commodity positions, which are not included in the table. These derivatives do not hedge all of our commodity price risk related to our forecasted sales of our natural gas and oil production and as a result, we are subject to commodity price risks on our remaining forecasted natural gas and oil production.

					10 Percent Increase						10 Percent Decrease
		Fair Value			Fair Value			(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

      During the fourth quarter of 2004, we designated a number of our Marketing and Trading segment’s natural gas derivative contracts as hedges of our Production segment’s natural gas production. As a result, the sensitivity of the derivatives in our Production segment to natural gas price changes increased and our Marketing and Trading segment’s Value-at-Risk decreased as of December 31, 2004 as discussed above.

      Additionally, as of December 31, 2004, our Marketing and Trading segment has entered into derivative contracts designed to provide El Paso with price protection from declines in natural gas prices in 2005 and 2006. These contracts provide us with a floor price of $6.00 per MMBtu on 60 TBtu of our natural gas production in 2005 and 120 TBtu in 2006. In the first quarter of 2005, we entered into additional contracts that provide El Paso with a floor price of $6.00 per MMBtu on 30 TBtu of our natural gas in 2007, and a ceiling price of $9.50 per MMBtu on 60 TBtu of our natural gas production in 2006. The commodity price risk

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associated with these contracts are not included in the sensitivity analysis, but rather are included in our Value-at-Risk calculation discussed above.

     Field Services

      Our Field Services segment does not significantly utilize financial instruments to mitigate our exposure to the natural gas liquids it retains in its processing operations since this exposure is not material to our overall operations.

Interest Rate Risk

Debt

      Many of our debt-related financial instruments and project financing arrangements are sensitive to changes in interest rates. The table below shows the maturity of the carrying amounts and related weighted-average interest rates on our interest-bearing securities, by expected maturity dates and the fair values of those securities. As of December 31, 2004 and 2003, the carrying amounts of short-term borrowings are representative of fair values because of the short-term maturity of these instruments. The fair value of the long-term securities has been estimated based on quoted market prices for the same or similar issues.

		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	%		—

Derivatives from Power Contract Restructuring Activities

      Derivatives associated with our power contract restructuring business of our Power segment are valued using estimated future market power prices and a discount rate that considers the appropriate U.S. Treasury rate plus a credit spread specific to the contract’s counterparty. We make adjustments to this discount rate when we believe that market changes in the rates result in changes in value that can be realized in a current transaction between willing parties. Since September 30, 2002, in order to provide for market risk, we have not reflected the increase in value that would result from decreases in U.S. Treasury rates because we believe the resulting increase in the value of these non-trading derivatives could not be realized in a current transaction between willing parties. To the extent there is commodity price risk associated with these derivative contracts, it is included in our Value-at-Risk calculation discussed above, but our exposure to changes in interest rates and credit spreads has not been included in our Value-at-Risk calculation. Historically, our interest rate risk associated with these contracts primarily related to UCF and Cedar Brakes I and II. As a result of the sale of UCF in 2004 and our sale of Cedar Brakes I and II in March 2005, our sensitivity to interest rate changes on our remaining restructured power contract derivatives will be minimal.

Foreign Currency Exchange Rate Risk

Debt

      Our exposure to foreign currency exchange rates relates primarily to changes in foreign currency rates on our Euro-denominated debt obligations. As of December 31, 2004, we have Euro-denominated debt with a

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principal amount of €1,050 million of which €550 million matures in 2006 and €500 million matures in 2009. As of December 31, 2004 and 2003, we had swaps that effectively converted €725 million and €625 million of debt into $766 million and $645 million. The remaining principal at December 31, 2004 and 2003 of €325 million and €425 million was subject to foreign currency exchange risk.

      In March 2005, we repurchased approximately €528 million of our debt maturing in 2006. After this repurchase, our unhedged Euro-denominated debt that is subject to foreign currency exchange risk totaled €172 million. As a result, a hypothetical ten percent increase or decrease in the Euro/USD exchange rate of 1.3188 as of the date of repurchase, with all other variables held constant, would increase or decrease the carrying value of our remaining unhedged Euro-denominated debt after the repurchase by approximately $23 million.

Power Contracts

      Several of our international power plants in Asia, Central America, South America and Europe have long-term power sales contracts that are denominated in the local country’s currencies. As a result, we are subject to foreign currency exchange risk related to these power sales contracts. We do not believe that this exposure is material to our operations and have not chosen to mitigate this exposure.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Financial Statements and Related Reports

      Below is an index to the financial statements and notes contained in Item 8, Financial Statements and Supplementary Data.

		Page
Consolidated Statements of Income			90
Consolidated Balance Sheets			91
Consolidated Statements of Cash Flows			93
Consolidated Statements of Stockholders’ Equity			95
Consolidated Statements of Comprehensive Income			96
Notes to Consolidated Financial Statements			97
	1.   Basis of Presentation and Significant Accounting Policies		97
	2.   Acquisitions and Consolidations		107
	3.   Divestitures		112
	4.   Restructuring Costs		116
	5.   Loss on Long-Lived Assets		118
	6.   Other Income and Other Expenses		119
	7.   Income Taxes		120
	8.   Earnings Per Share		123
	9.   Fair Value of Financial Instruments		123
	10.  Price Risk Management Activities		123
	11.  Inventory		129
	12.  Regulatory Assets and Liabilities		129
	13.  Other Assets and Liabilities		130
	14.  Property, Plant and Equipment		131
	15.  Debt, Other Financing Obligations and Other Credit Facilities		131
	16.  Preferred Interests of Consolidated Subsidiaries		138
	17.  Commitments and Contingencies		139
	18.  Retirement Benefits		149
	19.  Capital Stock		153
	20.  Stock-Based Compensation		153
	21.  Business Segment Information		155
	22.  Investments in, Earnings from and Transactions with Unconsolidated Affiliates		160
Report of Independent Registered Public Accounting Firm			168
Supplemental Financial Information
	Supplemental Selected Quarterly Financial Information (Unaudited)		171
	Supplemental Natural Gas and Oil Operations (Unaudited)		172
	Schedule II — Valuation and Qualifying Accounts		181

89

EL PASO CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(In millions, except per common share amounts)

		Year Ended December 31,
								2002
		2004			2003			(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		1,092			860			181
	Western Energy Settlement		—			104			899
	Taxes, other than income taxes		253			295			254
			5,668			6,263			7,052
Operating income (loss)			206			405			(171	)
Earnings (losses) from unconsolidated affiliates			559			363			(214	)
Other income			189			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			(777	)		(1,074	)		(1,883	)
Income taxes			25			(551	)		(641	)
Loss from continuing operations			(802	)		(523	)		(1,242	)
Discontinued operations, net of income taxes			(146	)		(1,396	)		(425	)
Cumulative effect of accounting changes, net of income taxes			—			(9	)		(208	)
Net loss		$	(948	)	$	(1,928	)	$	(1,875	)
Basic and diluted loss per common share
	Loss from continuing operations	$	(1.25	)	$	(0.87	)	$	(2.22	)
	Discontinued operations, net of income taxes		(0.23	)		(2.34	)		(0.76	)
	Cumulative effect of accounting changes, net of income taxes		—			(0.02	)		(0.37	)
	Net loss	$	(1.48	)	$	(3.23	)	$	(3.35	)
Basic and diluted average common shares outstanding			639			597			560

See accompanying notes.

90

EL PASO CORPORATION

CONSOLIDATED BALANCE SHEETS

(In millions, except share amounts)

				December 31,
						2003
				2004		(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		592
	Other				179		210
			Total current assets		5,632		8,922
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				1,534		1,660
	Gathering and processing systems				171		334
	Other				882		998
					36,973		36,244
	Less accumulated depreciation, depletion and amortization				18,161		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	$	36,942

See accompanying notes.

91

EL PASO CORPORATION

CONSOLIDATED BALANCE SHEETS — (Continued)

(In millions, except share amounts)

				December 31,
							2003
				2004			(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				1,311			1,551
	Western Energy Settlement				351			415
	Other				2,076			2,047
					4,764			4,794
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				(2,855	)		(1,907	)
	Accumulated other comprehensive income				48			11
	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		3,439			4,352
			Total liabilities and stockholders’ equity	$	31,383		$	36,942

See accompanying notes.

92

EL PASO CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

					Year Ended December 31,
											2002
					2004			2003			(Restated)(1)
Cash flows from operating activities
	Net loss				$	(948	)	$	(1,928	)	$	(1,875	)
	Less loss from discontinued operations, net of income taxes					(146	)		(1,396	)		(425	)
	Net loss before discontinued operations					(802	)		(532	)		(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				(38	)		(686	)		(685	)
		Cumulative effect of accounting changes				—			9			208
		Loss on long-lived assets				1,092			785			181
		Losses (earnings) from unconsolidated affiliates, adjusted for cash distributions				(224	)		(17	)		521
		Other non-cash income items				451			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 restatement.

See accompanying notes.

93

EL PASO CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS — (Continued)

(In millions)

				Year Ended December 31,
										2002
				2004			2003			(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 restatement.

See accompanying notes.

94

EL PASO CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In millions except for per share amounts)

			For the Years Ended December 31,
			2004						2003						2002
			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						(1,907	)					21						2,387
	Net loss						(948	)					(1,928	)					(1,875	)
	Dividends ($0.87 per share)						—						—						(491	)
		Balance at end of year					(2,855	)					(1,907	)					21
Accumulated other comprehensive income (loss):
	Balance at beginning of year						11						(235	)					(18	)
	Other comprehensive income (loss)						37						246						(217	)
		Balance at end of year					48						11						(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		$	3,439			632		$	4,352			599		$	5,750

See accompanying notes.

95

EL PASO CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In millions)

				Year Ended December 31,
										2002
				2004			2003			(Restated)
Net loss				$	(948	)	$	(1,928	)	$	(1,875	)
	Foreign currency translation adjustments (net of income tax of $10 in 2004)				7			159			(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)		37			246			(217	)
Comprehensive loss				$	(911	)	$	(1,682	)	$	(2,092	)

See accompanying notes.

96

EL PASO CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of Presentation and Significant Accounting Policies

     Basis of Presentation

      Our consolidated financial statements include the accounts of all majority-owned and controlled subsidiaries after the elimination of all significant intercompany accounts and transactions. Our results for all periods presented reflect our Canadian and certain other international natural gas and oil production operations, petroleum markets and coal mining businesses as discontinued operations. Additionally, our financial statements for prior periods include reclassifications that were made to conform to the current year presentation. Those reclassifications did not impact our reported net loss or stockholders’ equity.

     Restatement

      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 Statement of Financial Accounting Standards (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 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 related 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. Below are the effects of our restatements:

			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	)

		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

97

      The restatement did not impact 2003 and 2004 reported income amounts, except that we recorded an adjustment related to these periods of $(19) million in the fourth quarter of 2004. The components of this adjustment were immaterial to all previously reported interim and annual periods.

     Principles of Consolidation

      We consolidate entities when we either (i) have the ability to control the operating and financial decisions and policies of that entity or (ii) are allocated a majority of the entity’s losses and/or returns through our variable interests in that entity. The determination of our ability to control or exert significant influence over an entity and if we are allocated a majority of the entity’s losses and/or returns involves the use of judgment. We apply the equity method of accounting where we can exert significant influence over, but do not control, the policies and decisions of an entity and where we are not allocated a majority of the entity’s losses and/or returns. We use the cost method of accounting where we are unable to exert significant influence over the entity. See Note 2 for a discussion of our adoption of an accounting standard that impacted our consolidation principles in 2004.

     Use of Estimates

      The preparation of financial statements in conformity with accounting principles generally accepted in the U.S. requires the use of estimates and assumptions that affect the amounts we report as assets, liabilities, revenues and expenses and our disclosures in these financial statements. Actual results can, and often do, differ from those estimates.

     Accounting for Regulated Operations

      Our interstate natural gas pipelines and storage operations are subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Of our regulated pipelines, TGP, EPNG, SNG, CIG, WIC, CPG and MPC follow the regulatory accounting principles prescribed under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. ANR discontinued the application of SFAS No. 71 in 1996. The accounting required by SFAS No. 71 differs from the accounting required for businesses that do not apply its provisions. Transactions that are generally recorded differently as a result of applying regulatory accounting requirements include the capitalization of an equity return component on regulated capital projects, postretirement employee benefit plans, and other costs included in, or expected to be included in, future rates. Effective December 31, 2004, ANR Storage began re-applying the provisions of SFAS No. 71.

      We perform an annual review to assess the applicability of the provisions of SFAS No. 71 to our financial statements, the outcome of which could result in the re-application of this accounting in some of our regulated systems or the discontinuance of this accounting in others.

     Cash and Cash Equivalents

      We consider short-term investments with an original maturity of less than three months to be cash equivalents.

      We maintain cash on deposit with banks and insurance companies that is pledged for a particular use or restricted to support a potential liability. We classify these balances as restricted cash in other current or non-current assets in our balance sheet based on when we expect this cash to be used. As of December 31, 2004, we had $180 million of restricted cash in current assets, and $180 million in other non-current assets. As of December 31, 2003, we had $590 million of restricted cash in current assets and $349 million in other non-current assets. Of the 2003 amounts, $468 million was related to funds escrowed for our Western Energy Settlement discussed in Note 17.

98

     Allowance for Doubtful Accounts

      We establish provisions for losses on accounts and notes receivable and for natural gas imbalances due from shippers and operators if we determine that we will not collect all or part of the outstanding balance. We regularly review collectibility and establish or adjust our allowance as necessary using the specific identification method.

     Inventory

      Our inventory consists of spare parts, natural gas in storage, optic fiber and power turbines. We classify all inventory as current or non-current based on whether it will be sold or used in the normal operating cycle of the assets, to which it relates, which is typically within the next twelve months. We use the average cost method to account for our inventories. We value all inventory at the lower of its cost or market value.

  Property, Plant and Equipment

      Our property, plant and equipment is recorded at its original cost of construction or, upon acquisition, at the fair value of the assets acquired. For assets we construct, we capitalize direct costs, such as labor and materials, and indirect costs, such as overhead, interest and in our regulated businesses that apply the provisions of SFAS No. 71, an equity return component. We capitalize the major units of property replacements or improvements and expense minor items. Included in our pipeline property balances are additional acquisition costs, which represent the excess purchase costs associated with purchase business combinations allocated to our regulated interstate systems. These costs are amortized on a straight-line basis, and we do not recover these excess costs in our rates. The following table presents our property, plant and equipment by type, depreciation method and depreciable lives:

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.

     When we retire regulated property, plant and equipment, we charge accumulated depreciation and amortization for the original cost, plus the cost to remove, sell or dispose, less its salvage value. We do not recognize a gain or loss unless we sell an entire operating unit. We include gains or losses on dispositions of operating units in income.

      We capitalize a carrying cost on funds related to our construction of long-lived assets. This carrying cost consists of (i) an interest cost on our debt that could be attributed to the assets, which applies to all of our regulated transmission businesses and (ii) a return on our equity, that could be attributed to the assets, which only applies to regulated transmission businesses that apply SFAS No. 71. The debt portion is calculated based on the average cost of debt. Interest cost on debt amounts capitalized during the years ended December 31, 2004, 2003 and 2002, were $39 million, $31 million and $28 million. These amounts are included as a reduction of interest expense in our income statements. The equity portion is calculated using the most recent FERC approved equity rate of return. Equity amounts capitalized during the years ended December 31, 2004, 2003 and 2002 were $22 million, $19 million and $8 million. These amounts are included

99

as other non-operating income on our income statement. Capitalized carrying costs for debt and equity-financed construction are reflected as an increase in the cost of the asset on our balance sheet.

     Asset and Investment Impairments

      We apply the provisions of SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, and Accounting Principles Board Opinion (APB) No. 18, The Equity Method of Accounting for Investments in Common Stock, to account for asset and investment impairments. Under these standards, we evaluate an asset or investment for impairment when events or circumstances indicate that its carrying value may not be recovered. These events include market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset or investment and adverse changes in the legal or business environment such as adverse actions by regulators. When an event occurs, we evaluate the recoverability of our carrying value based on either (i) the long-lived asset’s ability to generate future cash flows on an undiscounted basis or (ii) the fair value of our investment in unconsolidated affiliates. If an impairment is indicated or if we decide to exit or sell a long-lived asset or group of assets, we adjust the carrying value of these assets downward, if necessary, to their estimated fair value, less costs to sell. Our fair value estimates are generally based on market data obtained through the sales process or an analysis of expected discounted cash flows. The magnitude of any impairments are impacted by a number of factors, including the nature of the assets to be sold and our established time frame for completing the sales, among other factors. We also reclassify the asset or assets as either held-for-sale or as discontinued operations, depending on, among other criteria, whether we will have any continuing involvement in the cash flows of those assets after they are sold.

     Natural Gas and Oil Properties

      We use the full cost method to account for our natural gas and oil properties. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of natural gas and oil reserves are capitalized. These capitalized amounts include the costs of unproved properties, internal costs directly related to acquisition, development and exploration activities, asset retirement costs and capitalized interest. This method differs from the successful efforts method of accounting for these activities. The primary differences between these two methods are the treatment of exploratory dry hole costs. These costs are generally expensed under successful efforts when the determination is made that measurable reserves do not exist. Geological and geophysical costs are also expensed under the successful efforts method. Under the full cost method, both dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is then periodically assessed for recoverability as discussed below.

      We amortize capitalized costs using the unit of production method over the life of our proved reserves. Capitalized costs associated with unproved properties are excluded from the amortizable base until these properties are evaluated. Future development costs and dismantlement, restoration and abandonment costs, net of estimated salvage values, are included in the amortizable base. Beginning January 1, 2003, we began capitalizing asset retirement costs associated with proved developed natural gas and oil reserves into our full cost pool, pursuant to SFAS No. 143, Accounting for Asset Retirement Obligations as discussed below.

      Our capitalized costs, net of related income tax effects, are limited to a ceiling based on the present value of future net revenues using end of period spot prices discounted at 10 percent, plus the lower of cost or fair market value of unproved properties, net of related income tax effects. If these discounted revenues are not greater than or equal to the total capitalized costs, we are required to write-down our capitalized costs to this level. We perform this ceiling test calculation each quarter. Any required write-downs are included in our income statement as a ceiling test charge. Our ceiling test calculations include the effects of derivative instruments we have designated as, and that qualify as, cash flow hedges of our anticipated future natural gas and oil production.

      When we sell or convey interests (including net profits interests) in our natural gas and oil properties, we reduce our reserves for the amount attributable to the sold or conveyed interest. We do not recognize a gain or loss on sales of our natural gas and oil properties, unless those sales would significantly alter the relationship

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between capitalized costs and proved reserves. We treat sales proceeds on non-significant sales as an adjustment to the cost of our properties.

     Goodwill and Other Intangible Assets

      Our intangible assets consist of goodwill resulting from acquisitions and other intangible assets. We apply SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets, to account for these intangibles. Under these standards, goodwill and intangibles that have indefinite lives are not amortized, but instead are periodically tested for impairment, at least annually, and whenever an event occurs that indicates that an impairment may have occurred. We amortize all other intangible assets on a straight-line basis over their estimated useful lives.

      The net carrying amounts of our goodwill as of December 31, 2004 and 2003, and the changes in the net carrying amounts of goodwill for the years ended December 31, 2004 and 2003 for each of our segments are as follows:

				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

      Our Field Services impairments resulted from the sale of substantially all of its interests in GulfTerra Energy Partners, as well as certain processing assets in our Field Services segment, to affiliates of Enterprise Products Partners L.P. As a result of these sales, we determined that the remaining assets in our Field Services segment could not support the goodwill in this segment. See Note 22 for a further discussion of the Enterprise transactions.

      Our Power segment recorded $22 million of goodwill in May 2003 in connection with the acquisition of Chaparral. In December 2003, we determined that we would sell substantially all of Chaparral’s power plants and, based on the bids received, we determined that this goodwill was not recoverable and we fully impaired this amount.

      Our Corporate and Other impairments resulted from weak industry conditions in our telecommunications operations. We also disposed of $42 million of goodwill related to our financial services businesses in 2003, which we had previously impaired by $44 million in 2002 based on weak industry conditions and our decision not to invest further capital in those businesses.

      In addition to our goodwill, we had a $181 million intangible asset as of December 31, 2003, related to our excess investment in our general partnership interest in GulfTerra. We disposed of this asset as a part of the Enterprise sales described above. We also had other intangible assets of $15 million and $5 million as of December 31, 2004 and 2003, primarily related to customer lists and other miscellaneous intangible assets.

     Pension and Other Postretirement Benefits

      We maintain several pension and other postretirement benefit plans. These plans require us to make contributions to fund the benefits to be paid out under the plans. These contributions are invested until the benefits are paid out to plan participants. We record benefit expense related to these plans in our income statement. This benefit expense is a function of many factors including benefits earned during the year by plan participants (which is a function of the employee’s salary, the level of benefits provided under the plan,

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actuarial assumptions, and the passage of time), expected return on plan assets and recognition of certain deferred gains and losses as well as plan amendments.

      We compare the benefits earned, or the accumulated benefit obligation, to the plan’s fair value of assets on an annual basis. To the extent the plan’s accumulated benefit obligation exceeds the fair value of plan assets, we record a minimum pension liability in our balance sheet equal to the difference in these two amounts. We do not record an additional minimum liability if it is less than the liability already accrued for the plan. If this difference is greater than the pension liability recorded on our balance sheet, however, we record an additional liability and an amount to other comprehensive loss, net of income taxes, on our financial statements.

      In 2004, we adopted FASB Staff Position (FSP) No. 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003. This pronouncement required us to record the impact of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 on our postretirement benefit plans that provide drug benefits that are covered by that legislation. The adoption of FSP No. 106-2 decreased our accumulated postretirement benefit obligation by $49 million, which is deferred as an actuarial gain in our postretirement benefit liabilities as of December 31, 2004. We expect that the adoption of this guidance will reduce our postretirement benefit expense by approximately $6 million in 2005.

  Revenue Recognition

      Our business segments provide a number of services and sell a variety of products. Our revenue recognition policies by segment are as follows:

      Pipelines revenues. Our Pipelines segment derives revenues primarily from transportation and storage services. We also derive revenue from sales of natural gas. For our transportation and storage services, we recognize reservation revenues on firm contracted capacity over the contract period regardless of the amount that is actually used. For interruptible or volumetric based services and for revenues under natural gas sales contracts, we record revenues when we complete the delivery of natural gas to the agreed upon delivery point and when natural gas is injected or withdrawn from the storage facility. Revenues in all services are generally based on the thermal quantity of gas delivered or subscribed at a price specified in the contract or tariff. We are subject to FERC regulations and, as a result, revenues we collect may be refunded in a final order of a pending or future rate proceeding or as a result of a rate settlement. We establish reserves for these potential refunds.

      Production revenues. Our Production segment derives revenues primarily through the physical sale of natural gas, oil, condensate and natural gas liquids. Revenues from sales of these products are recorded upon the passage of title using the sales method, net of any royalty interests or other profit interests in the produced product. When actual natural gas sales volumes exceed our entitled share of sales volumes, an overproduced imbalance occurs. To the extent the overproduced imbalance exceeds our share of the remaining estimated proved natural gas reserves for a given property, we record a liability. Costs associated with the transportation and delivery of production are included in cost of sales.

      Field Services revenues. Our Field Services segment derives revenues primarily from gathering and processing services and through the sale of commodities that are retained from providing these services. There are two general types of services: fee-based and make-whole. For fee-based services we recognize revenues at the time service is rendered based upon the volume of gas gathered, treated or processed at the contracted fee. For make-whole services, our fee consists of retainage of natural gas liquids and other by-products that are a result of processing, and we recognize revenues on these services at the time we sell these products, which generally coincides with when we provide the service.

      Power and Marketing and Trading revenues. Our Power and Marketing and Trading segments derive revenues from physical sales of natural gas and power and the management of their derivative contracts. Our derivative transactions are recorded at their fair value, and changes in their fair value are reflected in operating revenues. See a discussion of our income recognition policies on derivatives below under Price Risk

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Management Activities. Revenues on physical sales are recognized at the time the commodity is delivered and are based on the volumes delivered and the contractual or market price.

      Corporate. Revenue producing activities in our corporate operations primarily consist of revenues from our telecommunications business. We recognize revenues for our metro transport, collocation and cross-connect services in the month that the services are actually used by the customer.

  Environmental Costs and Other Contingencies

      We record liabilities when our environmental assessments indicate that remediation efforts are probable, and the costs can be reasonably estimated. We recognize a current period expense for the liability when clean-up efforts do not benefit future periods. We capitalize costs that benefit more than one accounting period, except in instances where separate agreements or legal or regulatory guidelines dictate otherwise. Estimates of our liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the EPA or other organizations. These estimates are subject to revision in future periods based on actual costs or new circumstances and are included in our balance sheet in other current and long-term liabilities at their undiscounted amounts. We evaluate recoveries from insurance coverage or government sponsored programs separately from our liability and, when recovery is assured, we record and report an asset separately from the associated liability in our financial statements.

      We recognize liabilities for other contingencies when we have an exposure that, when fully analyzed, indicates it is both probable that an asset has been impaired or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. Funds spent to remedy these contingencies are charged against a reserve, if one exists, or expensed. When a range of probable loss can be estimated, we accrue the most likely amount or at least the minimum of the range of probable loss.

  Price Risk Management Activities

      Our price risk management activities consist of the following activities:

• 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.

      We account for all derivative instruments under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. Under SFAS No. 133, derivatives are reflected in our balance sheet at their fair value as assets and liabilities from price risk management activities. We classify our derivatives as either current or non-current assets or liabilities based on their anticipated settlement date. We net derivative assets and liabilities for counterparties where we have a legal right of offset. See Note 10 for a further discussion of our price risk management activities.

      Prior to 2002, we also accounted for other non-derivative contracts, such as transportation and storage capacity contracts and physical natural gas inventories and exchanges, that were used in our energy trading business at their fair values under Emerging Issues Task Force (EITF) Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. In 2002, we adopted EITF Issue No. 02-3, Issues Related to Accounting for Contracts Involving Energy Trading and Risk Management Activities. As a result, we adjusted the carrying value of these non-derivative instruments to zero and now account for them on an accrual basis of accounting. We also adjusted the physical natural gas inventories used in our historical trading business to their cost (which was lower than market) and our physical natural gas exchanges to their expected settlement amounts and reclassified these amounts to inventory and accounts

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receivable and payable on our balance sheet. Upon our adoption of EITF Issue No. 02-3, we recorded a net loss of $343 million ($222 million net of income taxes) as a cumulative effect of an accounting change in our income statement, of which $118 million was the net adjustment to our natural gas inventories and exchanges and $225 million which was the net adjustment for our other non-derivative instruments.

      Our income statement treatment of changes in fair value and settlements of derivatives depends on the nature of the derivative instrument. Derivatives used in our hedging activities are reflected as either revenues or expenses in our income statements based on the nature and timing of the hedged transaction. Derivatives related to our power contract restructuring activities are reflected as either revenues (for settlements and changes in the fair values of the power sales contracts) or expenses (for settlements and changes in the fair values of the power supply agreements). The income statement presentation of our derivative contracts used in our historical energy trading activities is reported in revenue on a net basis (revenues net of the expenses of the physically settled purchases).

      In our cash flow statement, cash inflows and outflows associated with the settlement of our derivative instruments are recognized in operating cash flows, and any receivables and payables resulting from these settlements are reported as trade receivables and payables in our balance sheet.

      During 2002, we also adopted Derivatives Implementation Group (DIG) Issue No. C-16, Scope Exceptions: Applying the Normal Purchases and Sales Exception to Contracts that Combine a Forward Contract and Purchased Option Contract. DIG Issue No. C-16 requires that if a fixed-price fuel supply contract allows the buyer to purchase, at their option, additional quantities at a fixed-price, the contract is a derivative that must be recorded at its fair value. One of our unconsolidated affiliates, the Midland Cogeneration Venture Limited Partnership, recognized a gain on one of its fuel supply contract upon adoption of these new rules, and we recorded our proportionate share of this gain of $14 million, net of income taxes, as a cumulative effect of an accounting change in our income statement.

Income Taxes

      We record current income taxes based on our current taxable income, and we provide for deferred income taxes to reflect estimated future tax payments and receipts. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. We account for tax credits under the flow-through method, which reduces the provision for income taxes in the year the tax credits first become available. We reduce deferred tax assets by a valuation allowance when, based on our estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The estimates utilized in recognition of deferred tax assets are subject to revision, either up or down, in future periods based on new facts or circumstances.

      We maintain a tax accrual policy to record both regular and alternative minimum taxes for companies included in our consolidated federal and state income tax returns. The policy provides, among other things, that (i) each company in a taxable income position will accrue a current expense equivalent to its federal and state income taxes, and (ii) each company in a tax loss position will accrue a benefit to the extent its deductions, including general business credits, can be utilized in the consolidated returns. We pay all consolidated U.S. federal and state income taxes directly to the appropriate taxing jurisdictions and, under a separate tax billing agreement, we may bill or refund our subsidiaries for their portion of these income tax payments.

Foreign Currency Transactions and Translation

      We record all currency transaction gains and losses in income. These gains or losses are classified in our income statement based upon the nature of the transaction that gives rise to the currency gain or loss. For sales and purchases of commodities or goods, these gains or losses are included in operating revenue or expense. These gains and losses were insignificant in 2004, 2003 and 2002. For gains and losses arising through equity investees, we record these gains or losses as equity earnings. For gains or losses on foreign denominated debt, we include these gains or losses as a component of other expense. For the years ended December 31, 2004, 2003 and 2002, we recorded net foreign currency losses of $17 million, $100 million and $91 million primarily

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related to currency losses on our Euro-denominated debt. The U.S. dollar is the functional currency for the majority of our foreign operations. For foreign operations whose functional currency is deemed to be other than the U.S. dollar, assets and liabilities are translated at year-end exchange rates and the translation effects are included as a separate component of accumulated other comprehensive income (loss) in stockholders’ equity. The net cumulative currency translation gain recorded in accumulated other comprehensive income was $52 million and $45 million at December 31, 2004 and 2003. Revenues and expenses are translated at average exchange rates prevailing during the year.

Treasury Stock

      We account for treasury stock using the cost method and report it in our balance sheet as a reduction to stockholders’ equity. Treasury stock sold or issued is valued on a first-in, first-out basis. Included in treasury stock at both December 31, 2004, and 2003, were approximately 1.6 million shares and 1.7 million shares of common stock held in a trust under our deferred compensation programs.

Stock-Based Compensation

      We account for our stock-based compensation plans using the intrinsic value method under the provisions of Accounting Principles Board Opinion (APB) No. 25, Accounting for Stock Issued to Employees, and its related interpretations. We have both fixed and variable compensation plans, and we account for these plans using fixed and variable accounting as appropriate. Compensation expense for variable plans, including restricted stock grants, is measured using the market price of the stock on the date the number of shares in the grant becomes determinable. This measured expense is amortized into income over the period of service in which the grant is earned. Our stock options are granted under a fixed plan at the market value on the date of grant. Accordingly, no compensation expense is recognized. Had we accounted for our stock-based compensation using SFAS No. 123, Accounting for Stock-Based Compensation, rather than APB No. 25, the income (loss) and per share impacts on our financial statements would have been different. The following shows the impact on net loss and loss per share had we applied SFAS No. 123:

		Year Ended December 31,
								2002
		2004			2003			(Restated)
		(In millions, except per common
		share amounts)
Net loss, as reported		$	(948	)	$	(1,928	)	$	(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		$	(969	)	$	(1,978	)	$	(1,997	)
Loss per share:
	Basic and diluted, as reported	$	(1.48	)	$	(3.23	)	$	(3.35	)
	Basic and diluted, pro forma	$	(1.52	)	$	(3.31	)	$	(3.57	)

Accounting for Asset Retirement Obligations

      On January 1, 2003, we adopted SFAS No. 143, which requires that we record a liability for retirement and removal costs of long-lived assets used in our business. Our asset retirement obligations are associated with our natural gas and oil wells and related infrastructure in our Production segment and our natural gas storage wells in our Pipelines segment. We have obligations to plug wells when production on those wells is exhausted, and we abandon them. We currently forecast that these obligations will be met at various times, generally over the next fifteen years, based on the expected productive lives of the wells and the estimated timing of plugging and abandoning those wells.

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      In estimating the liability associated with our asset retirement obligations, we utilize several assumptions, including credit-adjusted discount rates, projected inflation rates, and the estimated timing and amounts of settling our obligations, which are based on internal models and external quotes. The following is a summary of our asset retirement liabilities and the significant assumptions we used at December 31:

	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.

     Our asset retirement liabilities are recorded at their estimated fair value utilizing the assumptions above, with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then depreciated over the remaining useful life of the long-lived asset to which that liability relates. An ongoing expense is also recognized for changes in the value of the liability as a result of the passage of time, which we record in depreciation, depletion and amortization expense in our income statement. In the first quarter of 2003, we recorded a charge as a cumulative effect of accounting change of approximately $9 million, net of income taxes, related to our adoption of SFAS No. 143.

      The net asset retirement liability as of December 31, reported in other current and non-current liabilities in our balance sheet, and the changes in the net liability for the year ended December 31, were as follows (in millions):

		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

      Our changes in estimate represent changes to the expected amount and timing of payments to settle our asset retirement obligations. These changes primarily result from obtaining new information about the timing of our obligations to plug our natural gas and oil wells and the costs to do so. Had we adopted SFAS No. 143 as of January 1, 2002, our aggregate current and non-current retirement liabilities on that date would have been approximately $187 million and our income from continuing operations and net income for the year ended December 31, 2002 would have been lower by $15 million. Basic and diluted earnings per share for the year ended December 31, 2002 would not have been materially affected.

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

      In May 2003, the Financial Accounting Standards Board (FASB) issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. This statement provides guidance on the classification of financial instruments as equity, as liabilities, or as both liabilities and equity. In particular, the standard requires that we classify all mandatorily redeemable securities as liabilities in the balance sheet. On July 1, 2003, we adopted the provisions of SFAS No. 150, and reclassified $625 million of our Capital Trust I and Coastal Finance I preferred interests from preferred interests of consolidated subsidiaries to long-term financing obligations in our balance sheet. We also began classifying dividends accrued on these preferred interests as interest and debt expense in our income statement. These dividends were $40 million in both 2004 and 2003. These dividends were recorded in interest and debt expense in 2004,

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and $20 million of our 2003 dividends were recorded in interest expense and $20 million were recorded as distributions on preferred interests in our income statement in 2003.

New Accounting Pronouncements Issued But Not Yet Adopted

      As of December 31, 2004, there were several accounting standards and interpretations that had not yet been adopted by us. Below is a discussion of significant standards that may impact us.

      Accounting for Stock-Based Compensation. In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment: an amendment of SFAS No. 123 and 95. This standard requires that companies measure and record the fair value of their stock based compensation awards at fair value on the date they are granted to employees. This fair value is determined based on a variety of assumptions, including volatility rates, forfeiture rates and the option pricing model used (e.g. binomial or Black Scholes). These assumptions could significantly differ from those we currently utilize in determining the proforma compensation expense included in our disclosures required under SFAS No. 123. This standard will also impact the manner in which we recognize the income tax impacts of our stock compensation programs in our financial statements. This standard is effective for interim periods beginning after June 15, 2005, at which time companies can select whether they will apply the standard retroactively by restating their historical financial statements or prospectively for new stock-based compensation arrangements and the unvested portion of existing arrangements. We will adopt this pronouncement in the third quarter of 2005 and are currently evaluating its impact on our consolidated financial statements.

      Accounting for Deferred Taxes on Foreign Earnings. In December 2004, the FASB issued FASB Staff Position (FSP) No. 109-2, Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004. FSP No. 109-2 clarified the existing accounting literature that requires companies to record deferred taxes on foreign earnings, unless they intend to indefinitely reinvest those earnings outside the U.S. This pronouncement will temporarily allow companies that are evaluating whether to repatriate foreign earnings under the American Jobs Creation Act of 2004 to delay recognizing any related taxes until that decision is made. This pronouncement also requires companies that are considering repatriating earnings to disclose the status of their evaluation and the potential amounts being considered for repatriation. The U.S. Treasury Department has not issued final guidelines for applying the repatriation provisions of the American Jobs Creation Act. We have not yet determined the potential range of our foreign earnings that could be impacted by this legislation and FSP No. 109-2, and we continue to evaluate whether we will repatriate any foreign earnings and the impact, if any, that this pronouncement will have on our financial statements.

2. Acquisitions and Consolidations

  Acquisitions

      During 2003, we acquired the remaining third party interests in our Chaparral and Gemstone investments and began consolidating them in the first and second quarters of 2003, respectively. We historically accounted for these investments using the equity method of accounting. Each of these acquisitions is discussed below.

      Chaparral. We entered into our Chaparral investment in 1999 to expand our domestic power generation business. Chaparral owned or had interests in 34 power plants in the United States that have a total generating capacity of 3,470 megawatts (based on Chaparral’s interest in the plants). These plants were primarily concentrated in the Northeastern and Western United States. Chaparral also owned several companies that own long-term derivative power agreements.

      At December 31, 2002, we owned 20 percent of Chaparral and the remaining 80 percent was owned by Limestone Electron Trust (Limestone). During 2003, we paid $1,175 million to acquire Limestone’s 80 percent interest in Chaparral. Limestone used $1 billion of these proceeds to retire notes that were previously guaranteed by us. We have reflected Chaparral’s results of operations in our income statement as though we acquired it on January 1, 2003. Had we acquired Chaparral effective January 1, 2002, the net

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increases (decreases) to our income statement for the year ended December 31, 2002, would have been as follows (in millions):

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

      During the first quarter of 2003, we recorded an impairment of our investment in Chaparral of $207 million before income taxes as further discussed in Note 22.

      The following table presents our allocation of the purchase price of Chaparral to its assets and liabilities prior to its consolidation and prior to the elimination of intercompany transactions. This allocation reflects the allocation of (i) our purchase price of $1,175 million; (ii) the carrying value of our initial investment of $252 million; and (iii) the impairment of $207 million (in millions):

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.

     Our allocation of the purchase price was based on valuations performed by an independent third party consultant, which were finalized in December 2003 with no significant changes to the initial purchase price allocation. These valuations were derived using discounted cash flow analyses and other valuation methods. These valuations indicated that the fair value of the net assets purchased from Chaparral was less than the purchase price we paid for Chaparral by $22 million, which we recorded as goodwill in our financial statements. See Note 1 for a discussion of the subsequent impairment of this goodwill.

      Gemstone. We entered into the Gemstone investment in 2001 to finance five major power plants in Brazil. Gemstone had investments in three power projects (Macae, Porto Velho and Araucaria) and also owned a preferred interest in two of our consolidated power projects, Rio Negro and Manaus. In 2003, we acquired the third-party investor’s (Rabobank) interest in Gemstone for approximately $50 million. Gemstone’s results of operations have been included in our consolidated financial statements since April 1, 2003. Had we acquired Gemstone effective January 1, 2003, our net income and basic and diluted earnings per share for the year ended December 31, 2003 would not have been affected, but our revenues and operating income would have been higher by $58 million and $41 million (amounts unaudited). Had the acquisition been effective January 1, 2002, our 2002 net income and our basic and diluted earnings per share

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would not have been affected, but our revenues and operating income would have been higher by $187 million and $134 million (amounts unaudited).

      Our allocation of the purchase price to the assets acquired and liabilities assumed upon our consolidation of Gemstone was as follows (in millions):

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

      Our allocation of the purchase price was based on valuations performed by an independent third party consultant, which were finalized in December 2003 with no significant changes to the initial purchase price allocation. These valuations were derived using discounted cash flow analyses and other valuation methods.

      Prior to our acquisitions of Chaparral and Gemstone, we had other balances, including loans and notes with Chaparral and Gemstone, which were eliminated upon consolidation. As a result, the overall impact on our consolidated balance sheet from acquiring these investments was different than the individual assets and liabilities acquired. The overall impact of these acquisitions on our consolidated balance sheet was an increase in our consolidated assets of $2.1 billion, an increase in our consolidated liabilities of approximately $2.4 billion (including an increase in our consolidated debt of approximately $2.2 billion) and a reduction of our preferred interests in consolidated subsidiaries of approximately $0.3 billion.

  Consolidations

      Variable Interest Entities. In 2003, the FASB issued Financial Interpretation (FIN) No. 46, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51. This interpretation defines a variable interest entity as a legal entity whose equity owners do not have sufficient equity at risk or a controlling financial interest in the entity. This standard requires a company to consolidate a variable interest entity if it is allocated a majority of the entity’s losses or returns, including fees paid by the entity.

      On January 1, 2004, we adopted this standard. Upon adoption, we consolidated Blue Lake Gas Storage Company and several other minor entities and deconsolidated a previously consolidated entity, EMA Power Kft. The overall impact of these actions is described in the following table:

	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	)

      Blue Lake Gas Storage owns and operates a 47 Bcf gas storage facility in Michigan. One of our subsidiaries operates the natural gas storage facility and we inject and withdraw all natural gas stored in the facility. We own a 75 percent equity interest in Blue Lake. This entity has $8 million of third party debt as of

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December 31, 2004 that is non-recourse to us. We consolidated Blue Lake because we are allocated a majority of Blue Lake’s losses and returns through our equity interest in Blue Lake.

      EMA Power Kft owns and operates a 69 gross MW dual-fuel-fired power facility located in Hungary. We own a 50 percent equity interest in EMA. Our equity partner has a 50 percent interest in EMA, supplies all of the fuel consumed and purchases all of the power generated by the facility. Our exposure to this entity is limited to our equity interest in EMA, which was approximately $43 million as of December 31, 2004. We deconsolidated EMA because our equity partner is allocated a majority of EMA’s losses and returns through its equity interest and its fuel supply and power purchase agreements with EMA.

      We have significant interests in a number of other variable interest entities. We were not required to consolidate these entities under FIN No. 46 and, as a result, our method of accounting for these entities did not change. As of December 31, 2004, these entities consisted primarily of 20 equity and cost investments held in our Power segment that had interests in power generation and transmission facilities with a total generating capacity of approximately 7,300 gross MW. We operate many of these facilities but do not supply a significant portion of the fuel consumed or purchase a significant portion of the power generated by these facilities. The long-term debt issued by these entities is recourse only to the power project. As a result, our exposure to these entities is limited to our equity investments in and advances to the entities ($1.1 billion as of December 31, 2004) and our guarantees and other agreements associated with these entities (a maximum of $80 million as of December 31, 2004).

      During our adoption of FIN No. 46, we attempted to obtain financial information on several potential variable interest entities but were unable to obtain that information. The most significant of these entities is the Cordova power project which is the counterparty to our largest tolling arrangement. Under this tolling arrangement, we supply on average a total of 54,000 MMBtu of natural gas per day to the entity’s two 274 gross MW power facilities and are obligated to market the power generated by those facilities through 2019. In addition, we pay that entity a capacity charge that ranges from $27 million to $32 million per year related to its power plants. The following is a summary of the financial statement impacts of our transactions with this entity for the year ended December 31, 2004 and 2003, and as of December 31, 2004 and December 31, 2003:

	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	)

      As of December 31, 2004, our financial statements included two consolidated entities that own a 238 MW power facility and a 158 MW power facility in Manaus, Brazil. In January 2005, we entered into agreements with Manaus Energia, under which Manaus Energia will supply substantially all of the fuel consumed and will purchase all of the power generated by the projects through January 2008, at which time Manaus Energia will assume ownership of the plants. We deconsolidated these two entities in January 2005 because Manaus Energia will assume ownership of the plants and since they will absorb a majority of the potential losses of the entities under the new agreements. The impact of this deconsolidation will be an increase in investments in unconsolidated affiliates of $103 million, a decrease in property, plant and equipment of $74 million and a net decrease in other assets and liabilities of $29 million in the first quarter of 2005.

      Lakeside. In 2003, we amended an operating lease agreement at our Lakeside Technology Center to add a guarantee benefiting the party who had invested in the lessor and to allow the third party and certain lenders to share in the collateral package that was provided to the banks under our previous $3 billion revolving credit facility. This guarantee reduced the investor’s risk of loss of its investment, resulting in our controlling the lessor. As a result, we consolidated the lessor. The consolidation of Lakeside Technology Center resulted in an increase in our property, plant and equipment of approximately $275 million and an increase in our long-term debt of approximately $275 million. In 2004, we repaid the $275 million that was scheduled to mature in 2006. Additionally, upon its consolidation, we recorded an asset impairment charge of approximately $127 million representing the difference between the facility’s estimated fair value and the

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residual value guarantee under the lease. Prior to its consolidation, this difference was being periodically expensed as part of operating lease expense over the term of the lease.

      Clydesdale. In 2003, we modified our Clydesdale financing arrangement to convert a third-party investor’s (Mustang Investors, L.L.C.) preferred ownership interest in one of our consolidated subsidiaries into a term loan that matures in equal quarterly installments through 2005. We also acquired a $10 million preferred interest in Mustang and guaranteed all of Mustang’s equity holder’s obligations. As a result, we consolidated Mustang which increased our long-term debt by $743 million and decreased our preferred interests of consolidated subsidiaries by $753 million. The $10 million preferred interest we acquired in Mustang was eliminated upon its consolidation. In December 2003, we repaid the remaining Clydesdale debt obligation (see Notes 15 and 16).

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3.  Divestitures

Sales of Assets and Investments

      During 2004, 2003 and 2002, we completed and announced the sale of a number of assets and investments in each of our business segments. The following table summarizes the proceeds from these sales:

		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.

     The following table summarizes the significant assets sold:

	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

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See Note 5 for a discussion of gains, losses and asset impairments related to the sales above.

      During 2005, we have either completed or announced the following sales:

•  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 power 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.

      Under SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, we classify assets to be disposed of as held for sale or, if appropriate, discontinued operations when they have received appropriate approvals by our management or Board of Directors and when they meet other criteria. These assets consist of certain of our domestic power plants and natural gas gathering and processing assets in our Field Services segment. As of December 31, 2004, we had assets held for sale of $75 million related to our Indian Springs natural gas gathering and processing facility, which was sold in January 2005, and four domestic power assets, which were impaired in previous years and which we expect to sell within the next twelve months. The following table details the items which are reflected as current assets and liabilities held for sale in our balance sheet as of December 31, 2003 (in millions).

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

      International Natural Gas and Oil Production Operations. During 2004, our Canadian and certain other international natural gas and oil production operations were approved for sale. As of December 31, 2004, we have completed the sale of all of our Canadian operations and substantially all of our operations in Indonesia for total proceeds of approximately $389 million. During 2004, we recognized approximately $99 million in losses based on our decision to sell these assets. We expect to complete the sale of the remainder of these properties by mid-2005.

      Petroleum Markets. During 2003, the sales of our petroleum markets businesses and operations were approved. These businesses and operations consisted of our Eagle Point and Aruba refineries, our asphalt business, our Florida terminal, tug and barge business, our lease crude operations, our Unilube blending operations, our domestic and international terminalling facilities and our petrochemical and chemical plants. Based on our intent to dispose of these operations, we were required to adjust these assets to their estimated

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fair value. As a result, we recognized pre-tax impairment charges during 2003 of approximately $1.5 billion related to these assets. These impairments were based on a comparison of the carrying value of these assets to their estimated fair value, less selling costs. We also recorded realized gains of approximately $59 million in 2003 from the sale of our Corpus Christi refinery, our asphalt assets and our Florida terminalling and marine assets.

      In 2004, we completed the sales of our Aruba and Eagle Point refineries for $880 million and used a portion of the proceeds to repay $370 million of debt associated with the Aruba refinery. We recorded realized losses of approximately $32 million in 2004, primarily from the sale of our Aruba and Eagle Point refineries. In addition, in 2004, we reclassified our petroleum ship charter operations from discontinued operations to continuing operations in our financial statements based on our decision to retain these operations. Our financial statements for all periods presented reflect this change.

      Coal Mining. In 2002, our Board of Directors authorized the sale of our coal mining operations and we recorded an impairment of $185 million. These operations consisted of fifteen active underground and two surface mines located in Kentucky, Virginia and West Virginia. The sale of these operations was completed in 2003 for $92 million in cash and $24 million in notes receivable, which were settled in the second quarter of 2004. We did not record a significant gain or loss on these sales.

      The petroleum markets, coal mining and our other international natural gas and oil production operations discussed above, are classified as discontinued operations in our financial statements for all of the historical periods presented. All of the assets and liabilities of these discontinued businesses are classified as current assets and liabilities as of December 31, 2004. The summarized financial results and financial position data of our discontinued operations were as follows:

				International
				Natural Gas
				and Oil
	Petroleum			Production			Coal
	Markets			Operations			Mining		Total
	(In millions)
Operating Results Data
Year Ended December 31, 2004
Revenues	$	787		$	31		$	—	$	818
Costs and expenses		(839	)		(53	)		—		(892	)
Loss on long-lived assets		(36	)		(99	)		—		(135	)
Other income		23			—			—		23
Interest and debt expense		(3	)		1			—		(2	)
Loss before income taxes		(68	)		(120	)		—		(188	)
Income taxes		2			(44	)		—		(42	)
Loss from discontinued operations, net of income taxes	$	(70	)	$	(76	)	$	—	$	(146	)

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				International
				Natural Gas
				and Oil
	Petroleum			Production			Coal
	Markets			Operations			Mining			Total
	(In millions)
Year Ended December 31, 2003
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	)		(33	)		5			(290	)
Gain (loss) from discontinued operations, net of income taxes	$	(1,304	)	$	(93	)	$	1		$	(1,396	)
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	)

						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

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					International
					Natural Gas
					and Oil
			Petroleum		Production
			Markets		Operations		Total
			(In millions)
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

      As a result of actions taken in 2002, 2003, and 2004, we incurred certain organizational restructuring costs included in operation and maintenance expense. On January 1, 2003, we adopted the provisions of SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities, and recognized restructuring costs applying the provisions of that standard. Prior to this date, we had recognized restructuring costs according to the provisions of EITF Issue No. 94-3, Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity. By segment, our restructuring costs for the years ended December 31, were as follows:

					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

      During the period from 2002 to 2004, we incurred substantial restructuring charges as part of our ongoing liquidity enhancement and cost reduction efforts. Below is a summary of these costs:

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      Employee severance, retention, and transition costs. During 2002, 2003, and 2004, we incurred employee severance costs, which included severance payments and costs for pension benefits settled under existing benefit plans. During this period, we eliminated approximately 1,900 full-time positions from our continuing business and approximately 1,200 positions related to businesses we discontinued in 2004, 900 full-time positions from our continuing businesses and approximately 1,800 positions related to businesses we discontinued in 2003, and 900 full-time positions through terminations in 2002. As of December 31, 2004, all but $15 million of the total employee severance, retention and transition costs had been paid.

      Office relocation and consolidation. In May 2004, we announced that we would begin consolidating our Houston-based operations into one location. This consolidation was substantially completed by the end of 2004. As a result, as of December 31, 2004, we had established an accrual totaling $80 million to record the discounted liability, net of estimated sub-lease rentals, for our obligations under our existing lease terms. These leases expire at various times through 2014. Of the approximate 888,000 square feet of office space that we lease, we have vacated approximately 741,000 square feet as of December 31, 2004. In addition, we have subleased approximately 238,000 square feet of this space in the third and fourth quarters of 2004. Actual moving expenses related to the relocation were insignificant and were expensed in the period that they were incurred. All amounts related to the relocation are expensed in our corporate operations.

      Other. In 2003, our contract termination and other costs included charges of approximately $44 million related to amounts paid for canceling or restructuring our obligations to transport LNG from supply areas to domestic and international market centers. In 2002, we incurred and paid fees of $40 million to eliminate stock price and credit rating triggers related to our Chaparral and Gemstone investments.

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5. Loss on Long-Lived Assets

      Loss on long-lived assets from continuing operations consists of realized gains and losses on sales of long-lived assets and impairments of long-lived assets including goodwill and other intangibles. During each of the three years ended December 31, our losses on long-lived assets were as follows:

								2002
			2004			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		197			—		—
		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		1,108			791		440
	Loss on long-lived assets			1,092			860		181
	(Gain) loss on investments in unconsolidated affiliates (1)			(129	)		176		612
	(Gain) loss on assets and investments		$	963		$	1,036	$	793

⁽¹⁾  See Note 22 for a further description of these gains and losses.

Net Realized (Gain) Loss

      Our 2004 net realized gain was primarily related to $10 million of gains in our Power segment and $8 million of gains in our Corporate operations from the disposition of assets offset by the $11 million loss on the sale of our South Texas assets in our Field Services segment.

      Our 2003 net realized loss was primarily related to a $74 million loss on an agreement to reimburse GulfTerra for a portion of future pipeline integrity costs on previously sold assets. We reduced this accrual by $9 million in 2004 (see Note 22). We also recorded a $67 million gain on the release of our purchase obligation for the Chaco facility and a $14 million gain on the sale of our north Louisiana and Mid-Continent midstream assets in our Field Services segment as well as a $75 million loss on and the termination of our Energy Bridge contracts in the Corporate and other segment and a $10 million loss on the sale of Mohawk River Funding I in our Power segment.

      Our 2002 net realized gain was primarily related to $245 million of net gains on the sales of our San Juan gathering assets, our Natural Buttes and Ouray gathering systems, our Dragon Trail gas processing plant and our Texas and New Mexico assets in our Field Services segment. See Note 3 for a further discussion of these divestitures.

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Asset Impairments

      Our impairment charges for the years ended December 31, 2004, 2003 and 2002, were recorded primarily in connection with our intent to dispose of, or reduce our involvement in, a number of assets.

      Our 2004 Power segment charges include a $227 million impairment on the sale of our domestic equity interests in Cedar Brakes I and II, which closed in the first quarter of 2005, a $167 million impairment of our Manaus and Rio Negro power facilities in Brazil as a result of renegotiating and extending their power purchase agreements, and a $30 million impairment on our consolidated Asian assets in connection with our decision to sell these assets. In addition, in 2004, we impaired UCF prior to its sale by $98 million and recorded impairments of $73 million related to the sales of various other power assets and turbines. Our 2003 and 2002 Power segment impairment charges were primarily a result of our planned sale of domestic power assets (including our turbines classified in long-term assets).

      Our Field Services charges include a $480 million impairment of the goodwill associated with the Enterprise sale in 2004 on which we realized an offsetting pretax gain of $507 million recorded in earnings from unconsolidated affiliates, a $24 million impairment on the sales or abandonment of assets in 2004, an impairment of our south Texas processing facilities of $167 million in 2003 based on our planned sale of these facilities to Enterprise (see Note 22), and a $66 million impairment that resulted from our decision to sell our north Louisiana gathering facilities in 2002.

      Our corporate telecommunications charge includes an impairment of our investment in the wholesale metropolitan transport services, primarily in Texas, of $269 million in 2003 (including a writedown of goodwill of $163 million) and a 2003 impairment of our Lakeside Technology Center facility of $127 million based on an estimate of what the asset could be sold for in the current market. In 2002, we incurred $168 million of corporate telecommunication charges related to the impairment of our long-haul fiber network and right-of-way assets.

      For additional asset impairments on our discontinued operations and investments in unconsolidated affiliates, see Notes 3 and 22. For additional discussion on goodwill and other intangibles, see Note 1.

6. Other Income and Other Expenses

      The following are the components of other income and other expenses from continuing operations for each of the three years ended December 31:

			2004		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			9		12		—
	Favorable resolution of non-operating contingent obligations			—		9		38
	Gain on early extinguishment of debt			—		—		21
	Other			43		44		26
		Total	$	189	$	203	$	197

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			2004		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.

7. Income Taxes

      Our pretax loss from continuing operations is composed of the following for each of the three years ended December 31:

							2002
	2004			2003			(Restated)
	(In millions)
U.S.	$	(698	)	$	(1,330	)	$	(2,282	)
Foreign		(79	)		256			399
	$	(777	)	$	(1,074	)	$	(1,883	)

      The following table reflects the components of income tax expense (benefit) included in loss from continuing operations for each of the three years ended December 31:

									2002
			2004			2003			(Restated)
			(In millions)
Current
	Federal		$	(15	)	$	36		$	(15	)
	State			39			58			27
	Foreign			39			41			32
				63			135			44
Deferred
	Federal			(63	)		(636	)		(679	)
	State			(5	)		(57	)		(11	)
	Foreign			30			7			5
				(38	)		(686	)		(685	)
		Total income taxes	$	25		$	(551	)	$	(641	)

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      Our income taxes, included in loss from continuing operations, differs from the amount computed by applying the statutory federal income tax rate of 35 percent for the following reasons for each of the three years ended December 31:

								2002
		2004			2003			(Restated)
		(In millions, except rates)
Income taxes at the statutory federal rate of 35%		$	(272	)	$	(376	)	$	(659	)
Increase (decrease)
	Abandonments and sales of foreign investments		(4	)		(124	)		—
	Valuation allowances		18			(57	)		44
	Foreign income taxed at different rates		155			(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			4			2
	Non-conventional fuel tax credits		—			—			(11	)
	Non-deductible goodwill impairments		139			29			—
	Other		(7	)		(3	)		(15	)
Income taxes		$	25		$	(551	)	$	(641	)
Effective tax rate			(3	)%		51	%		34	%

      The following are the components of our net deferred tax liability related to continuing operations as of December 31:

							2003
				2004			(Restated)
				(In millions)
Deferred tax liabilities
	Property, plant and equipment			$	2,590		$	2,147
	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			3,223
Deferred tax assets
	Net operating loss and tax credit carryovers
		U.S. federal			1,196			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				387			276
	Valuation allowance				(51	)		(9	)
			Total deferred tax asset		2,434			2,333
Net deferred tax liability				$	893		$	890

      In 2004, Congress proposed but failed to enact legislation which would disallow deductions for certain settlements made to or on behalf of governmental entities. It is possible Congress will reintroduce similar legislation in 2005. If enacted, this tax legislation could impact the deductibility of the Western Energy

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Settlement and could result in a write-off of some or all of the associated tax benefits. In such event, our tax expense would increase. Our total tax benefits related to the Western Energy Settlement were approximately $400 million as of December 31, 2004.

      Historically, we have not recorded U.S. deferred tax liabilities on book versus tax basis differences in our Asian power investments because it was our historical intent to indefinitely reinvest the earnings from these projects outside the U.S. In 2004, our intent on these assets changed such that we now intend to use the proceeds from the sale within the U.S. As a result, we recorded deferred tax liabilities which, as of December 31, 2004 were $39 million, representing those instances where the book basis in our investments in the Asian power projects exceeded the tax basis. At this time, however, due to uncertainties as to the manner, timing and approval of the sales, we have not recorded deferred tax assets for those instances where the tax basis of our investments exceeded the book basis, except in instances where we believe the realization of the asset is assured. As of December 31, 2004, total deferred tax assets recorded on our Asian investments was $6 million.

      Cumulative undistributed earnings from the remainder of our foreign subsidiaries and foreign corporate joint ventures (excluding our Asian power assets discussed above) have been or are intended to be indefinitely reinvested in foreign operations. Therefore, no provision has been made for any U.S. taxes or foreign withholding taxes that may be applicable upon actual or deemed repatriation. At December 31, 2004, the portion of the cumulative undistributed earnings from these investments on which we have not recorded U.S. income taxes was approximately $551 million. If a distribution of these earnings were to be made, we might be subject to both foreign withholding taxes and U.S. income taxes, net of any allowable foreign tax credits or deductions. However, an estimate of these taxes is not practicable. For these same reasons, we have not recorded a provision for U.S. income taxes on the foreign currency translation adjustments recorded in accumulated other comprehensive income other than $4 million included in the deferred tax liability we recorded related to our investment in our Asian power projects.

      The tax effects associated with our employees’ non-qualified dispositions of employee stock purchase plan stock, the exercise of non-qualified stock options and the vesting of restricted stock, as well as restricted stock dividends are included in additional paid-in-capital in our balance sheets.

      As of December 31, 2004, we have U.S. federal alternative minimum tax credits of $283 million and state alternative minimum assessment tax credits of $1 million that carryover indefinitely, $1 million of general business credit carryovers for which the carryover periods end at various times in the years 2012 through 2021, capital loss carryovers of $87 million and charitable contributions carryovers of $2 million for which the carryover periods end in 2008. The table below presents the details of our federal and state net operating loss carryover periods as of December 31, 2004:

	Carryover Period
	2005		2006-2010		2011-2015		2016-2024		Total
	(In millions)
U.S. federal net operating loss	$	—	$	7	$	—	$	3,118	$	3,125
State net operating loss		8		849		412		987		2,256

      We also had $103 million of foreign net operating loss carryovers that carryover indefinitely. Usage of our U.S. federal carryovers is subject to the limitations provided under Sections 382 and 383 of the Internal Revenue Code as well as the separate return limitation year rules of IRS regulations.

      We record a valuation allowance to reflect the estimated amount of deferred tax assets which we may not realize due to the uncertain availability of future taxable income or the expiration of net operating loss and tax credit carryovers. As of December 31, 2004, we maintained a valuation allowance of $37 million related to state net operating loss carryovers, $7 million related to our estimated ability to realize state tax benefits from the deduction of the charge we took related to the Western Energy Settlement, $5 million related to foreign deferred tax assets for book impairments and ceiling test charges, $1 million related to a general business credit carryover and $1 million related to other carryovers. As of December 31, 2003, we maintained a valuation allowance of $5 million related to state tax benefits of the Western Energy Settlement, $1 million

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related to state net operating loss carryovers, $1 million related to foreign deferred tax assets for ceiling test charges and $1 million related to a general business credit carryover and $1 million related to other carryovers. The change in our valuation allowances from December 31, 2003 to December 31, 2004 is primarily related to an additional valuation allowance for State of New Jersey legislation that limited use of net operating loss carryovers, an increase in valuation allowances on foreign impairments of assets and an increase in the state valuation allowance related to the Western Energy Settlement.

      We are currently under audit by the IRS and other taxing authorities, and our audits are in various stages of completion. The tax years for 1995-2000 are pending with the IRS Appeals Office related to The Coastal Corporation, with which we merged in 2001. We anticipate that the Appeals proceedings for 1995-1997 will be finalized within 12 months, while the other years will take longer to complete. The IRS has completed its examination of El Paso’s tax years through 2000. The 2001-2002 tax years are currently under examination, which we anticipate will be completed within 12 months. There may be additional proceedings in the IRS Appeals Office with respect to this examination. We maintain a reserve for tax contingencies that management believes is adequate, and as audits are finalized we will make appropriate adjustments to those estimates.

8. Earnings Per Share

      We incurred losses from continuing operations during the three years ended December 31, 2004. Accordingly, we excluded a number of securities for the years ended December 2004, 2003, and 2002, from the determination of diluted earnings per share due to their antidilutive effect on loss per common share. These included stock options, restricted stock, trust preferred securities, equity security units, and convertible debentures. Additionally, in 2003, we excluded shares related to our remaining stock obligation under the Western Energy Settlement (see Note 17 for further information). For a further discussion of these instruments, see Notes 15 and 20.

9. Fair Value of Financial Instruments

      The following table presents the carrying amounts and estimated fair values of our financial instruments as of December 31, 2004 and 2003.

	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

      As of December 31, 2004 and 2003, our carrying amounts of cash and cash equivalents, short-term borrowings, and trade receivables and payables represented fair value because of the short-term nature of these instruments. The fair value of long-term debt with variable interest rates approximates its carrying value because of the market-based nature of the interest rate. We estimated the fair value of debt with fixed interest rates based on quoted market prices for the same or similar issues. See Note 10 for a discussion of our methodology of determining the fair value of the derivative instruments used in our price risk management activities.

10. Price Risk Management Activities

      The following table summarizes the carrying value of the derivatives used in our price risk management activities as of December 31, 2004 and 2003. In the table, derivatives designated as hedges consist of instruments used to hedge our natural gas and oil production as well as instruments to hedge our interest rate and currency risks on long-term debt. Derivatives from power contract restructuring activities relate to power

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purchase and sale agreements that arose from our activities in that business and other commodity-based derivative contracts relate to our historical energy trading activities.

			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.

     Our derivative contracts are recorded in our financial statements at fair value. The best indication of fair value is quoted market prices. However, when quoted market prices are not available, we estimate the fair value of those derivatives. Due to major industry participants exiting or reducing their trading activities in 2002 and 2003, the availability of reliable commodity pricing data from market-based sources that we used in estimating the fair value of our derivatives was significantly limited for certain locations and for longer time periods. Consequently, we now use an independent pricing source for a substantial amount of our forward pricing data beyond the current two-year period. For forward pricing data within two years, we use commodity prices from market-based sources such as the New York Mercantile Exchange. For periods beyond two years, we use a combination of commodity prices from market-based sources and other forecasted settlement prices from an independent pricing source to develop price curves, which we then use to estimate the value of settlements in future periods based on the contractual settlement quantities and dates. Finally, we discount these estimated settlement values using a LIBOR curve, except as described below for our restructured power contracts. Additionally, contracts denominated in foreign currencies are converted to U.S. dollars using market-based, foreign exchange spot rates.

      We record valuation adjustments to reflect uncertainties associated with the estimates we use in determining fair value. Common valuation adjustments include those for market liquidity and those for the credit-worthiness of our contractual counterparties. To the extent possible, we use market-based data together with quantitative methods to measure the risks for which we record valuation adjustments and to determine the level of these valuation adjustments.

      The above valuation techniques are used for valuing derivative contracts that have historically been accounted for as trading activities, as well as for those that are used to hedge our natural gas and oil production. We have adjusted this method to determine the fair value of our restructured power contracts. Our restructured power derivatives use the same methodology discussed above for determining the forward settlement prices but are discounted using a risk free interest rate, adjusted for the individual credit spread for each counterparty to the contract. Additionally, no liquidity valuation adjustment is provided on these derivative contracts since they are intended to be held through maturity.

          Derivatives Designated as Hedges

      We engage in two types of hedging activities: hedges of cash flow exposure and hedges of fair value exposure. Hedges of cash flow exposure, which primarily relate to our natural gas and oil production hedges and foreign currency and interest rate risks on our long-term debt, are designed to hedge forecasted sales transactions or limit the variability of cash flows to be received or paid related to a recognized asset or liability.

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Hedges of fair value exposure are entered into to protect the fair value of a recognized asset, liability or firm commitment. When we enter into the derivative contract, we designate the derivative as either a cash flow hedge or a fair value hedge. Our hedges of our foreign currency exposure are designated as either cash flow hedges or fair value hedges based on whether the interest on the underlying debt is converted to either a fixed or floating interest rate. Changes in derivative fair values that are designated as cash flow hedges are deferred in accumulated other comprehensive income (loss) to the extent that they are effective and are not included in income until the hedged transactions occur and are recognized in earnings. The ineffective portion of a cash flow hedge’s change in value is recognized immediately in earnings as a component of operating revenues in our income statement. Changes in the fair value of derivatives that are designated as fair value hedges are recognized in earnings as offsets to the changes in fair values of the related hedged assets, liabilities or firm commitments.

      We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives, strategies for undertaking various hedge transactions and our methods for assessing and testing correlation and hedge ineffectiveness. All hedging instruments are linked to the hedged asset, liability, firm commitment or forecasted transaction. We also assess whether these derivatives are highly effective in offsetting changes in cash flows or fair values of the hedged items. We discontinue hedge accounting prospectively if we determine that a derivative is no longer highly effective as a hedge or if we decide to discontinue the hedging relationship.

      A discussion of each of our hedging activities is as follows:

      Cash Flow Hedges. A majority of our commodity sales and purchases are at spot market or forward market prices. We use futures, forward contracts and swaps to limit our exposure to fluctuations in the commodity markets with the objective of realizing a fixed cash flow stream from these activities. We also have fixed rate foreign currency denominated debt that exposes us to changes in exchange rates between the foreign currency and U.S. dollar. We use currency swaps to convert the fixed amounts of foreign currency due under foreign currency denominated debt to U.S. dollar amounts. As of December 31, 2004 and 2003, we have swaps that convert approximately €275 million of our debt to $255 million, substantially all of which were cancelled with the payoff of the underlying hedged debt in March 2005. A summary of the impacts of our cash flow hedges included in accumulated other comprehensive loss, net of income taxes, as of December 31, 2004 and 2003 follows.

		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 $52 million and $45 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.

     In December 2004, we designated a number of our 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

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reclassified this amount to derivatives designated as hedges, specifically cash flow hedges, beginning in the fourth quarter of 2004.

      For the years ended December 31, 2004, 2003 and 2002, we recognized net losses of $1 million, $2 million and $4 million, net of income taxes, in our loss from continuing operations related to the ineffective portion of all cash flow hedges.

      Fair Value Hedges. We have fixed rate U.S. dollar and foreign currency denominated debt that exposes us to paying higher than market rates should interest rates decline. We use interest rate swaps to effectively convert the fixed amounts of interest due under the debt agreements to variable interest payments based on LIBOR plus a spread. As of December 31, 2004 and 2003, these derivatives had a net fair value of $117 million and $33 million. Specifically, we had derivatives with fair value losses of $20 million and $19 million as of December 31, 2004 and 2003, that converted the interest rate on $440 million and $350 million of our U.S. dollar denominated debt to a floating weighted average interest rate of LIBOR plus 4.2%. Additionally, we had derivatives with fair values of $137 million and $52 million as of December 31, 2004 and 2003, that converted approximately €450 million and €350 million of our debt to $511 million and $390 million. These derivatives also converted the interest rate on this debt to a floating weighted average interest rate of LIBOR plus 3.9% as of December 31, 2004, and LIBOR plus 3.7% as of December 31, 2003. We have recorded the fair value of those derivatives as a component of long-term debt and the related accrued interest. For the year ended December 31, 2002, the net financial statement impact of our fair value hedges was immaterial.

      In March 2005, we repurchased approximately €528 million of debt, of which approximately €100 million were hedged with fair value hedges. As a result of the repurchase, we removed the hedging designation on, and subsequently cancelled, these derivative contracts.

      In December 2002, we reduced the volumes of foreign currency exchange risk that we have hedged for our debt, and we removed the hedging designation on derivatives that had a net fair value gain of $3 million and $6 million at December 31, 2004 and 2003. These amounts, which are reflected in long-term debt, will be reclassified to income as the interest and principal on the debt are paid through 2009.

Power Contract Restructuring Activities

      During 2001 and 2002, we conducted power contract restructuring activities that involved amending or terminating power purchase contracts at existing power facilities. In a restructuring transaction, we would eliminate the requirement that the plant provide power from its own generation to the customer of the contract (usually a regulated utility) and replace that requirement with a new contract that gave us the ability to provide power to the customer from the wholesale power market. In conjunction with these power restructuring activities, our Marketing and Trading segment generally entered into additional market-based contracts with third parties to provide the power from the wholesale power market, which effectively “locked in” our margin on the restructured transaction as the difference between the contracted rate in the restructured sales contract and the wholesale market rates on the purchase contract at the time.

      Prior to a restructuring, the power plant and its related power purchase contract were accounted for at their historical cost, which was either the cost of construction or, if acquired, the acquisition cost. Revenues and expenses prior to the restructuring were, in most cases, accounted for on an accrual basis as power was generated and sold from the plant.

      Following a restructuring, the accounting treatment for the power purchase agreement changed since the restructured contract met the definition of a derivative. In addition, since the power plant no longer had the exclusive obligation to provide power under the original, dedicated power purchase contract, it operated as a peaking merchant facility, generating power only when it was economical to do so. Because of this significant change in its use, the plant’s carrying value was typically written down to its estimated fair value. These changes also often required us to terminate or amend any related fuel supply and/or steam agreements, and enter into other third party and intercompany contracts such as transportation agreements, associated with operating the merchant facility. Finally, in many cases power contract restructuring activities also involved

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contract terminations that resulted in cash payments by the customer to cancel the underlying dedicated power contract.

      In 2002, we completed a power contract restructuring on our consolidated Eagle Point power facility and applied the accounting described above to that transaction. We also employed the principles of our power contract restructuring business in reaching a settlement of a dispute under our Nejapa power contract which included a cash payment to us. We recorded these payments as operating revenues in our Power segment. We also terminated a power contract at our consolidated Mount Carmel facility in exchange for a $50 million cash payment. For the year ended December 31, 2002, our consolidated power restructuring activities had the following effects on our consolidated financial statements (in millions):

		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.

     As a result of our credit downgrade and economic changes in the power market, we are no longer pursuing additional power contract restructuring activities and are actively seeking to sell or otherwise dispose of our existing restructured power contracts. In 2004, we completed the sales of UCF (which is the restructured Eagle Point power contract) and Mohawk River Funding IV. (See Note 3 for a discussion of these sales.) Mohawk River Funding, III (“MRF III”) had a prior purchase agreement (“USGen PPA”) with USGen New England, Inc. (“USGen”). USGen filed for Chapter 11 bankruptcy protection and the USGen PPA was terminated automatically as a result of the bankruptcy filing. MRF III filed a proof of claim in the bankruptcy case and the bankruptcy court issued an order resolving the claim. The order is not final at this time and may be subject to change which could result in a final award that is either more or less than the receivable that has been recorded. Additionally, in March 2005, we completed the sale of Cedar Brakes I and II and the related restructured derivative power contracts.

Other Commodity-Based Derivatives

      Our other commodity-based derivatives primarily relate to our historical trading activities, which include the services we provide in the energy sector that we entered into with the objective of generating profits on or benefiting from movements in market prices, primarily related to the purchase and sale of energy commodities. Our derivatives in our trading portfolio had a fair value liability of $61 million and $488 million as of December 31, 2004 and 2003. In December 2004, we designated a number of our 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.

Credit Risk

      We are subject to credit risk related to our financial instrument assets. Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of their

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contractual obligations. We measure credit risk as the estimated replacement costs for commodities we would have to purchase or sell in the future, plus amounts owed from counterparties for delivered and unpaid commodities. These exposures are netted where we have a legally enforceable right of setoff. We maintain credit policies with regard to our counterparties in our price risk management activities to minimize overall credit risk. These policies require (i) the evaluation of potential counterparties’ financial condition (including credit rating), (ii) collateral under certain circumstances (including cash in advance, letters of credit, and guarantees), (iii) the use of margining provisions in standard contracts, and (iv) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty.

      We use daily margining provisions in our financial contracts, most of our physical power agreements and our master netting agreements, which require a counterparty to post cash or letters of credit when the fair value of the contract exceeds the daily contractual threshold. The threshold amount is typically tied to the published credit rating of the counterparty. Our margining collateral provisions also allow us to terminate a contract and liquidate all positions if the counterparty is unable to provide the required collateral. Under our margining provisions, we are required to return collateral if the amount of posted collateral exceeds the amount of collateral required. Collateral received or returned can vary significantly from day to day based on the changes in the market values and our counterparty’s credit ratings. Furthermore, the amount of collateral we hold may be more or less than the fair value of our derivative contracts with that counterparty at any given period.

      The following table presents a summary of our counterparties in which we had net financial instrument asset exposure as of December 31, 2004 and 2003.

		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.

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     We have approximately 125 counterparties, most of which are energy marketers. Although most of our counterparties are not currently rated as below investment grade, if one of our counterparties fails to perform, such as in the case of Enron (see Note 17 for a further discussion of the Enron Bankruptcy), we may recognize an immediate loss in our earnings, as well as additional financial impacts in the future delivery periods to the extent a replacement contract at the same prices and quantities cannot be established.

      One electric utility customer, Public Service Electric and Gas Company (PSEG), comprised 42 percent and 66 percent of our net financial instrument asset exposure as of December 31, 2004 and 2003. Our net financial instrument asset exposure to PSEG was eliminated with the sale of our interests in Cedar Brakes I and II in the first quarter of 2005. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.

11. Inventory

      We have the following current inventory as of December 31:

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

      We also have the following non-current inventory that is included in other assets in our balance sheets as of December 31:

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

12. Regulatory Assets and Liabilities

      Our regulatory assets and liabilities are included in other current and non-current assets and liabilities in our balance sheets. These balances are presented in our balance sheets on a gross basis. Below are the details of our regulatory assets and liabilities for our regulated interstate systems that apply the provisions of SFAS No. 71 as of December 31, which are recoverable over various periods:

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

129

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.

13. Other Assets and Liabilities

      Below is the detail of our other current and non-current assets and liabilities on our balance sheets as of December 31:

			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)		$	933	$	962
	Notes receivable from affiliates			287		349
	Restricted cash (Note 1)			180		349
	Unamortized debt expenses			192		246
	Regulatory assets (Note 12)			155		143
	Long-term receivables			343		108
	Notes receivable			46		113
	Turbine inventory (Note 11)			76		98
	Other investments			48		60
	Assets of discontinued operations			—		405
	Other			53		163
		Total	$	2,313	$	2,996

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			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)			84		96
	Deposits			39		67
	Obligations under swap agreement (Note 15)			—		49
	Other postretirement benefits (Note 18)			38		45
	Asset retirement obligations (Note 1)			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)		$	763	$	450
	Other postretirement and employment benefits (Note 18)			248		272
	Obligations under swap agreement (Note 15)			—		208
	Regulatory liabilities (Note 12)			228		203
	Asset retirement obligations (Note 1)			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)			15		101
	Deferred compensation			56		60
	Pipeline integrity liability (Note 22)			50		69
	Liabilities of discontinued operations			—		3
	Other			64		90
		Total	$	2,076	$	2,047

14. Property, Plant and Equipment

      At December 31, 2004 and 2003, we had approximately $0.8 billion and $1.0 billion of construction work-in-progress included in our property, plant and equipment.

      As of December 31, 2004 and 2003, TGP, EPNG and ANR have excess purchase costs associated with their acquisition. Total excess costs on these pipelines were approximately $5 billion and accumulated depreciation was approximately $1.3 billion. These excess costs are being amortized over the life of the related pipeline assets, and our amortization expense during the three years ended December 31, 2004, 2003, and 2002 was approximately $76 million, $74 million and $71 million. The adoption of SFAS No. 142 did not impact these amounts since they were included as part of our property, plant and equipment, rather than as goodwill. We do not currently earn a return on these excess purchase costs from our rate payers.

15. Debt, Other Financing Obligations and Other Credit Facilities

		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

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      Our debt and other credit facilities consist of both short and long-term borrowings with third parties and notes with our affiliated companies. During 2004, we entered into a new $3 billion credit agreement and sold entities with debt obligations. A summary of our actions is as follows (in millions):

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.

     Short-Term Financing Obligations

      We had the following short-term borrowings and other financing obligations as of December 31:

	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

     Long-Term Financing Obligations

      Our long-term financing obligations outstanding consisted of the following as of December 31:

			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

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				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

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      During 2004 and to date in 2005, we had the following changes in our long-term financing obligations:

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 date of filing						$	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 date of filing						$	5,919

(1)	This debt was consolidated as a result of adopting FIN No. 46 (see Note 2).
(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 for additional information on the repurchase of the derivative contracts.

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     Aggregate maturities of the principal amounts of long-term financing obligations for the next 5 years and in total thereafter are as follows (in millions):

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.

     Included above in 2005 is $320 million of debt associated with our Macae project in Brazil, as a result of an event of default on Macae’s non-recourse debt. (See Note 17 for additional details on the event of default.) Also included in 2005 are approximately $114 million of notes and debentures that holders have the option to redeem in 2005, prior to their stated maturities. Of this amount, $75 million is eligible for redemption solely in 2005 and, if not redeemed, will be reclassified to long-term debt in 2006.

      Included in the “thereafter” line of the table above are $600 million of other debentures that holders have an option to redeem in 2007 prior to their stated maturities and $822 million of zero coupon convertible debentures. The zero-coupon debentures have a maturity value of $1.6 billion, are due 2021 and have a yield to maturity of 4 percent. The holders can cause us to repurchase these debentures at their option in years 2006, 2011 and 2016, should they make this election, we can choose to settle in cash or common stock at a price which approximates market. These debentures are convertible into 7,468,726 shares of our common stock, which is based on a conversion rate of 4.7872 shares per $1,000 principal amount at maturity. This rate is equal to a conversion price of $94.604 per share of our common stock.

     Credit Facilities

      In November 2004, we replaced our previous $3 billion revolving credit facility, which was scheduled to mature in June 2005, with a new $3 billion credit agreement with a group of lenders. This $3 billion credit agreement consists of a $1.25 billion five-year term loan; a $1 billion three-year revolving credit facility; and a $750 million, five-year letter of credit facility. Certain of our subsidiaries, EPNG, TGP, ANR and CIG, also continue to be eligible borrowers under the new credit agreement. Additionally, El Paso and certain of its subsidiaries have guaranteed borrowings under the new credit agreement, which is collateralized by our interests in EPNG, TGP, ANR, CIG, WIC, ANR Storage Company and Southern Gas Storage Company.

      As of December 31, 2004, we had $1.25 billion outstanding under the term loan and had utilized approximately all of the $750 million letter of credit facility and approximately $0.4 billion of the $1 billion revolving credit facility to issue letters of credit. The term loan accrues interest at LIBOR plus 2.75 percent, matures in November 2009, and will be repaid in increments of $5 million per quarter with the unpaid balance due at maturity. Under the new revolving credit facility, which matures in November 2007, we can borrow funds at LIBOR plus 2.75 percent or issue letters of credit at 2.75 percent plus a fee of 0.25 percent of the amount issued. We pay an annual commitment fee of 0.75 percent on any unused capacity under the revolving credit facility. The terms of the new $750 million letter of credit facility provides us the ability to issue letters of credit or borrow any unused capacity under the letter of credit facility as revolving loans with a maturity in November 2009. We pay LIBOR plus 2.75 percent on any amounts borrowed under the letter of credit facility, and 2.85 percent on letters of credit and unborrowed funds.

Restrictive Covenants

      Our restrictive covenants includes restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on the sales of assets, capitalization requirements, dividend restrictions, cross default and cross-acceleration and prepayment of debt provisions. A breach of any of these

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covenants could result in acceleration of our debt and other financial obligations and that of our subsidiaries. Under our new credit agreement the significant debt covenants and cross defaults are:

(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.

      In addition to the above restrictions and default provisions, we and/or our subsidiaries are subject to a number of additional restrictions and covenants. These restrictions and covenants include limitations of additional debt at some of our subsidiaries; limitations on the use of proceeds from borrowing at some of our subsidiaries; limitations, in some cases, on transactions with our affiliates; limitations on the occurrence of liens; potential limitations on the abilities of some of our subsidiaries to declare and pay dividends and potential limitations on some of our subsidiaries to participate in our cash management program, and limitations on our ability to prepay debt.

      We also issued various guarantees securing financial obligations of our subsidiaries and unaudited affiliates with similar covenants as the above facilities.

      With respect to guarantees issued by our subsidiaries, the most significant debt covenant, in addition to the covenants discussed above, is that El Paso CGP must maintain a minimum net worth of $850 million. If breached, the amounts guaranteed by its guaranty agreements could be accelerated. The guaranty agreements also have a $30 million cross-acceleration provision.

      In addition, three of our subsidiaries have indentures associated with their public debt that contain $5 million cross-acceleration provisions. These indentures state that should an event of default occur resulting in the acceleration of other debt obligations of such subsidiaries in excess of $5 million, the long-term debt obligations containing such provisions could be accelerated. The acceleration of our debt would adversely affect our liquidity position and in turn, our financial condition.

     Other Financing Arrangements

      Capital Trust I. In March 1998, we formed El Paso Energy Capital Trust I, a wholly owned subsidiary, which issued 6.5 million of 4.75 percent trust convertible preferred securities for $325 million. We own all of the Common Securities of Trust I. Trust I exists for the sole purpose of issuing preferred securities and investing the proceeds in 4.75 percent convertible subordinated debentures we issued due 2028, their sole asset. Trust I’s sole source of income is interest earned on these debentures. This interest income is used to pay the obligations on Trust I’s preferred securities. We provide a full and unconditional guarantee of Trust I’s preferred securities.

      Trust I’s preferred securities are non-voting (except in limited circumstances), pay quarterly distributions at an annual rate of 4.75 percent, carry a liquidation value of $50 per security plus accrued and unpaid

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distributions and are convertible into our common shares at any time prior to the close of business on March 31, 2028, at the option of the holder at a rate of 1.2022 common shares for each Trust I preferred security (equivalent to a conversion price of $41.59 per common share). During 2003, the outstanding amounts of these securities were reclassified as long-term debt from preferred interests in our subsidiaries as a result of a new accounting standard.

      Coastal Finance I. Coastal Finance I is an indirect wholly owned business trust formed in May 1998. Coastal Finance I completed a public offering of 12 million mandatory redemption preferred securities for $300 million. Coastal Finance I holds subordinated debt securities issued by our wholly owned subsidiary, El Paso CGP, that it purchased with the proceeds of the preferred securities offering. Cumulative quarterly distributions are being paid on the preferred securities at an annual rate of 8.375 percent of the liquidation amount of $25 per preferred security. Coastal Finance I’s only source of income is interest earned on these subordinated debt securities. This interest income is used to pay the obligations on Coastal Finance I’s preferred securities. The preferred securities are mandatorily redeemable on the maturity date, May 13, 2038, and may be redeemed at our option on or after May 13, 2003. The redemption price to be paid is $25 per preferred security, plus accrued and unpaid distributions to the date of redemption. El Paso CGP provides a guarantee of the payment of obligations of Coastal Finance I related to its preferred securities to the extent Coastal Finance I has funds available. We have no obligation to provide funds to Coastal Finance I for the payment of or redemption of the preferred securities outside of our obligation to pay interest and principal on the subordinated debt securities. During 2003, the amounts outstanding of these securities were reclassified as long-term debt from preferred interests in our subsidiaries as a result of a new accounting standard.

      Equity Security Units. In June 2002, we issued 11.5 million, 9 percent equity security units. Equity security units consist of two securities: i) a purchase contract on which we pay quarterly contract adjustment payments at an annual rate of 2.86 percent and that requires its holder to buy our common stock on a stated settlement date of August 16, 2005, and ii) a senior note due August 16, 2007, with a principal amount of $50 per unit, and on which we pay quarterly interest payments at an annual rate of 6.14 percent. The senior notes we issued had a total principal value of $575 million and are pledged to secure the holders’ obligation to purchase shares of our common stock under the purchase contracts. In December 2003, we completed a tender offer to exchange 6,057,953 of the outstanding equity security units, which represented approximately 53 percent of the total units outstanding. In the exchange, we issued a total of 15,182,972 shares of our common stock that had a total market value of $119 million, and paid $59 million in cash.

      When the remaining purchase contracts are settled in 2005, the contract provides for us to issue common stock. At that time, the proceeds will be allocated between common stock and additional paid-in capital. The number of common shares issued will depend on the prior consecutive 20-trading day average closing price of our common stock determined on the third trading day immediately prior to the stock purchase date. We will issue a minimum of approximately 11 million shares and up to a maximum of approximately 14 million shares on the settlement date, depending on our average stock price.

      Non-Recourse Project Financings. Many of our power subsidiaries and investments have borrowed a material portion of the costs to acquire or construct their domestic and international power assets. Such borrowings are made with recourse only to the project company and assets (i.e. without recourse to El Paso). On occasion, events have occurred in connection with several of our projects that have either constituted an event of default under the loan agreements or could constitute an event of default upon delivery of a notice from the lenders and the failure of the subsidiary or investee to cure the event during an applicable grace period. Currently, we have one consolidated subsidiary, Macae, where the power off taker to the project, Petrobras, has not paid all amounts owed under its contract with the plant. This non-payment has created an event of default on that project under its loan agreements. Accordingly, we classified approximately $320 million as current debt as of December 31, 2004. (See Note 17 for additional information on our investment in Macae.) In addition, we have several other projects that we account for as equity investments that are in default under their loan agreements, including Saba, Berkshire and East Asia Power. We have written off all of our investment in both the Berkshire and East Asia Power facilities and have a $9 million interest in Saba. There is no recourse to El Paso under the loans at these investments. In addition, we have had events of default or other events that could lead to an event of default upon notice from the lenders on

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other projects, but we do not believe any of these defaults will have a material impact on our or our subsidiaries’ financial statements.

Letters of Credit

      We enter into letters of credit in the ordinary course of our operating activities. As of December 31, 2004, we had outstanding letters of credit of approximately $1.3 billion, of which $107 million was supported with cash collateral, and $1.2 billion were issued under our credit agreement. Included in this amount were $0.9 billion of letters of credit securing our recorded obligations related to price risk management activities.

Available Capacity Under Shelf Registration Statements

      We maintain a shelf registration statement with the SEC that allows us to issue a combination of debt, equity and other instruments, including trust preferred securities of two wholly owned trusts, El Paso Capital Trust II and El Paso Capital Trust III. If we issue securities from these trusts, we would be required to issue full and unconditional guarantees on these securities. As of December 31, 2004, we had $926 million remaining capacity under this shelf registration statement; however, we are unable to access this capacity until January 2006, due to the untimely filing of our 2003 annual and quarterly 2004 financial statements.

16. Preferred Interests of Consolidated Subsidiaries

      In the past, we entered into financing transactions that have been accomplished through the sale of preferred interests in consolidated subsidiaries. During 2003, we repaid approximately $2 billion of these preferred interests, reclassified $625 million to long-term financing obligations as a result of adopting SFAS No. 150 (see Note 1) and eliminated $300 million in consolidation because we acquired the holder of those preferred interests. Our remaining preferred interest is discussed below.

      El Paso Tennessee Preferred Stock. In 1996, El Paso Tennessee Pipeline Co. (EPTP) issued 6 million shares of publicly registered 8.25 percent cumulative preferred stock with a par value of $50 per share for $300 million. The preferred stock is redeemable, at our option, at a redemption price equal to $50 per share, plus accrued and unpaid dividends, at any time. EPTP indirectly owns our marketing and trading businesses, substantially all of our domestic and international power businesses, and TGP. While not required, the following financial information is intended to provide additional information of EPTP to its preferred security holders:

		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	)

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		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

Legal Proceedings

      Western Energy Settlement. In June 2004, our master settlement agreement, along with other separate settlement agreements, became effective with a number of public and private claimants, including the states of California, Washington, Oregon and Nevada. This resolves the principal litigation, investigations, claims and regulatory proceedings arising out of the sale or delivery of natural gas and/or electricity to the western U.S. (the Western Energy Settlement). As part of the Western Energy Settlement, we admitted no wrongdoing but agreed, among other things, to make various cash payments and modify an existing power supply contract. We also entered into a Joint Settlement Agreement or JSA where we agreed, subject to the limitations in the JSA, to (1) make 3.29 Bcf/d of capacity available to California to the extent shippers sign firm contracts for that capacity, (2) maintain facilities sufficient to physically deliver 3.29 Bcf/d to California; (3) construct facilities which we completed in 2004, (4) clarify certain shippers’ recall rights on the system and (5) bar any of our affiliated companies from obtaining additional firm capacity on our EPNG pipeline system during a five year period from the effective date of the settlement.

      In June 2003, El Paso, the California Public Utilities Commission (CPUC), Pacific Gas and Electric Company, Southern California Edison Company, and the City of Los Angeles filed the JSA described above with the FERC. In November 2003, the FERC approved the JSA with minor modifications. Our east of California shippers filed requests for rehearing, which were denied by the FERC on March 30, 2004. Certain shippers have appealed the FERC’s ruling to the U.S. Court of Appeals for the District of Columbia, where this matter is pending. We expect this appeal to be fully briefed by the summer of 2005.

      During the fourth quarter of 2002, we recorded an $899 million pretax charge related to the Western Energy Settlement. During 2003, we recorded additional pretax charges of $104 million based upon reaching definitive settlement agreements. Charges and expenses associated with the Western Energy Settlement are included in operations and maintenance expense in our consolidated statements of income. When the settlement became effective in June 2004, $602 million was released to the settling parties. This amount is shown as a reduction of our cash flows from operations in the second quarter of 2004. Of the amount released, $568 million had been previously held in an escrow account pending final approval of the settlement. The release of these restricted funds is included as an increase in our cash flows from investing activities. Our remaining obligation as of December 31, 2004 under the Western Energy Settlement consists of a discounted 20-year cash payment obligation of $395 million and a price reduction under a power supply contract, which is included in our price risk management activities. In connection with the Western Energy Settlement, we provided collateral in the form of natural gas and oil properties to secure our remaining cash payment obligation. The collateral requirement is being reduced as payments under the 20 year obligation are made. For an issue regarding the potential tax deductibility of our Western Energy Settlement charges, see Note 7.

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          Shareholder/Derivative/ERISA Litigation

      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.

      Cash Balance Plan Lawsuit. In December 2004, a lawsuit entitled Tomlinson, et al. v. El Paso Corporation and El Paso Corporation Pension Plan was filed in U.S. District Court for Denver, Colorado. The lawsuit seeks class action status and alleges that the change from a final average earnings formula pension plan to a cash balance pension plan, the accrual of benefits under the plan, and the communications about the change violate the ERISA and/or the Age Discrimination in Employment Act. Our costs and legal exposure related to this lawsuit are not currently determinable.

      Retiree Medical Benefits Matters. We currently serve as the plan administrator for a medical benefits plan that covers a closed group of retirees of the Case Corporation who retired on or before June 30, 1994. Case was formerly a subsidiary of Tenneco, Inc. that was spun off prior to our acquisition of Tenneco in 1996. In connection with the Tenneco-Case Reorganization Agreement of 1994, Tenneco assumed the obligation to provide certain medical and prescription drug benefits to eligible retirees and their spouses. We assumed this obligation as a result of our merger with Tenneco. However, we believe that our liability for these benefits is limited to certain maximums, or caps, and costs in excess of these maximums are assumed by plan participants. In 2002, we and Case were sued by individual retirees in federal court in Detroit, Michigan in an action entitled Yolton et al. v. El Paso Tennessee Pipeline Company and Case Corporation. The suit alleges, among other things, that El Paso violated ERISA, and that Case should be required to pay all amounts above the cap. Although such amounts will vary over time, the amounts above the cap have recently been approximately $1.8 million per month. Case further filed claims against El Paso asserting that El Paso is obligated to indemnify, defend, and hold Case harmless for the amounts it would be required to pay. In February 2004, a judge ruled that Case would be required to pay the amounts incurred above the cap. Furthermore, in September 2004, a judge ruled that pending resolution of this matter, El Paso must indemnify and reimburse Case for the monthly amounts above the cap. Our motion for reconsideration of these orders was denied in November 2004. These rulings have been appealed. In the meantime, El Paso will indemnify Case for any payments Case makes above the cap. While we believe we have meritorious defenses to the

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plaintiffs’ claims and to Case’s crossclaim, if we were required to ultimately pay for all future amounts above the cap, and if Case were not found to be responsible for these amounts, our exposure could be as high as $400 million, on an undiscounted basis.

      Natural Gas Commodities Litigation. Beginning in August 2003, several lawsuits were filed against El Paso and El Paso Marketing L.P. (EPM), formerly El Paso Merchant Energy L.P., our affiliate, in which plaintiffs alleged, in part, that El Paso, EPM and other energy companies conspired to manipulate the price of natural gas by providing false price reporting information to industry trade publications that published gas indices. Those cases, all filed in the United States District Court for the Southern District of New York, are as follows: Cornerstone Propane Partners, L.P. v. Reliant Energy Services Inc., et al.; Roberto E. Calle Gracey v. American Electric Power Company, Inc., et al.; and Dominick Viola v. Reliant Energy Services Inc., et al. In December 2003, those cases were consolidated with others into a single master file in federal court in New York for all pre-trial purposes. In September 2004, the court dismissed El Paso from the master litigation. EPM and approximately 27 other energy companies remain in the litigation. In January 2005 a purported class action lawsuit styled Leggett et al. v Duke Energy Corporation et al. was filed against El Paso, EPM and a number of other energy companies in the Chancery Court of Tennessee for the Twenty-Fifth Judicial District at Somerville on behalf of the all residential and commercial purchasers of natural gas in the state of Tennessee during the past three years. Plaintiffs allege the defendants conspired to manipulate the price of natural gas by providing false price reporting information to industry trade publications that published gas indices. The Company has also had similar claims asserted by individual commercial customers. Our costs and legal exposure related to these lawsuits and claims are not currently determinable.

      Grynberg. A number of our subsidiaries were named defendants in actions filed in 1997 brought by Jack Grynberg on behalf of the U.S. Government under the False Claims Act. Generally, these complaints allege an industry-wide conspiracy to underreport the heating value as well as the volumes of the natural gas produced from federal and Native American lands, which deprived the U.S. Government of royalties. The plaintiff in this case seeks royalties that he contends the government should have received had the volume and heating value been differently measured, analyzed, calculated and reported, together with interest, treble damages, civil penalties, expenses and future injunctive relief to require the defendants to adopt allegedly appropriate gas measurement practices. No monetary relief has been specified in this case. These matters have been consolidated for pretrial purposes (In re: Natural Gas Royalties Qui Tam Litigation, U.S. District Court for the District of Wyoming, filed June 1997). Motions to dismiss have been filed on behalf of all defendants. Our costs and legal exposure related to these lawsuits and claims are not currently determinable.

      Will Price (formerly Quinque). A number of our subsidiaries are named as defendants in Will Price, et al. v. Gas Pipelines and Their Predecessors, et al., filed in 1999 in the District Court of Stevens County, Kansas. Plaintiffs allege that the defendants mismeasured natural gas volumes and heating content of natural gas on non-federal and non-Native American lands and seek to recover royalties that they contend they should have received had the volume and heating value of natural gas produced from their properties been differently measured, analyzed, calculated and reported, together with prejudgment and postjudgment interest, punitive damages, treble damages, attorneys’ fees, costs and expenses, and future injunctive relief to require the defendants to adopt allegedly appropriate gas measurement practices. No monetary relief has been specified in this case. Plaintiffs’ motion for class certification of a nationwide class of natural gas working interest owners and natural gas royalty owners was denied in April 2003. Plaintiffs were granted leave to file a Fourth Amended Petition, which narrows the proposed class to royalty owners in wells in Kansas, Wyoming and Colorado and removes claims as to heating content. A second class action has since been filed as to the heating content claims. The plaintiffs have filed motions for class certification in both proceedings and the defendants have filed briefs in opposition thereto. Our costs and legal exposure related to these lawsuits and claims are not currently determinable.

      Bank of America. We are a named defendant, along with Burlington Resources, Inc., in two class action lawsuits styled as Bank of America, et al. v. El Paso Natural Gas Company, et al., and Deane W. Moore, et al. v. Burlington Northern, Inc., et al., each filed in 1997 in the District Court of Washita County, State of Oklahoma and subsequently consolidated by the court. The plaintiffs seek an accounting and damages for alleged royalty underpayments from 1982 to the present on natural gas produced from specified wells in

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Oklahoma, plus interest from the time such amounts were allegedly due, as well as punitive damages. The court has certified the plaintiff classes of royalty and overriding royalty interest owners, and the parties have completed discovery. The plaintiffs have filed expert reports alleging damages in excess of $1 billion. Pursuant to a recent summary judgment decision, the court ruled that claims previously released by the settlement of Altheide v. Meridian, a nation-wide royalty class action against Burlington and its affiliates are barred from being reasserted in this action. We believe that this ruling eliminates a material, but yet unquantified portion of the alleged class damages. While Burlington accepted our tender of the defense of these cases in 1997, pursuant to the spin-off agreement entered into in 1992 between EPNG and Burlington Resources, Inc., and had been defending the matter since that time, at the end of 2003 it asserted contractual claims for indemnity against us. A third action, styled Bank of America, et al. v. El Paso Natural Gas and Burlington Resources Oil and Gas Company, was filed in October 2003 in the District Court of Kiowa County, Oklahoma asserting similar claims as to specified shallow wells in Oklahoma, Texas and New Mexico. Defendants succeeded in transferring this action to Washita County. A class has not been certified. We have filed an action styled El Paso Natural Gas Company v. Burlington Resources, Inc. and Burlington Resources Oil and Gas Company, L.P. against Burlington in state court in Harris County relating to the indemnity issues between Burlington and us. That action is currently stayed. We believe we have substantial defenses to the plaintiffs’ claims as well as to the claims for indemnity by Burlington. Our costs and legal exposure related to these lawsuits and claims are not currently determinable.

      Araucaria. We own a 60 percent interest in a 484 MW gas-fired power project known as the Araucaria project located near Curitiba, Brazil. The Araucaria project has a 20-year power purchase agreement (PPA) with a government-controlled regional utility. In December 2002, the utility ceased making payments to the project and, as a result, the Araucaria project and the utility are currently involved in international arbitration over the PPA. A Curitiba court has ruled that the arbitration clause in the PPA is invalid, and has enjoined the project company from prosecuting its arbitration under penalty of approximately $173,000 in daily fines. The project company is appealing this ruling, and has obtained a stay order in any imposition of daily fines pending the outcome of the appeal. Our investment in the Araucaria project was $186 million at December 31, 2004. We have political risk insurance that covers a portion of our investment in the project. Based on the future outcome of our dispute under the PPA and depending on our ability to collect amounts from the utility or under our political risk insurance policies, we could be required to write down the value of our investment.

      Macae. We own a 928 MW gas-fired power plant known as the Macae project located near the city of Macae, Brazil with property, plant and equipment having a net book value of $700 million as of December 31, 2004. The Macae project revenues are derived from sales to the spot market, bilateral contracts and minimum capacity and revenue payments. The minimum capacity and energy revenue payments of the Macae project are paid by Petrobras until August 2007 under a participation agreement. Petrobras failed to make any payments that were due under the participation agreement for December 2004 and January 2005. In 2005, Petrobras obtained a ruling from a Brazilian court directing Petrobras to deposit one-half of the payments to a court account and to pay us the other half. We are appealing this ruling. Petrobras has also failed to make any payments required under the court order. As of December 31, 2004, our accounts receivable balance is approximately $20 million. Petrobras has also filed a notice of arbitration with an international arbitration institution that effectively seeks rescission of the participation agreement and reimbursement of a portion of the capacity payments that it has made. If such claim were successful, it would result in a termination of the minimum revenue payments as well as Petrobras’s obligation to provide a firm gas supply to the project through 2012. We believe we have substantial defenses to the claims of Petrobras and will vigorously defend our legal rights. In addition, we will continue to seek reasonable negotiated settlements of this dispute, including the restructuring of the participation agreement or the sale of the plant. Macae has non-recourse debt of approximately $320 million at December 31, 2004, and Petrobras’ non-payment has created an event of default under the applicable loan agreements. As a result, we have classified the entire $320 million of debt as current. We also have restricted cash balances of approximately $76 million as of December 31, 2004, which are reflected in current assets, related to required debt service reserve balances, debt service payment accounts and funds held for future distribution by Macae. We have also issued cash collateralized letters of credit of approximately $47 million as part of funding the required debt service reserve accounts. The

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restricted cash related to these letters of credit has also been classified as a current asset. In light of the default of Petrobras under the participation agreement and the potential inability of Macae to continue to make ongoing payments under its loan agreements, one or more of the lenders could exercise certain remedies under the loan agreements in the future, one of which could be an acceleration of the amounts owed under the loan agreements which could ultimately result in the lenders foreclosing on the Macae project.

      In light of the pending arbitration proceedings, we have evaluated whether any impairment of our investment in the project is required at December 31, 2004. Based upon our review of the possible outcomes of the arbitration and potential settlements of the dispute, we do not believe that an impairment of our investment is required at this time. However, if our assessment of the potential outcomes of the arbitration or settlement opportunities changes, we may be required to write down some or all of our investment in the project. In the event that the lenders call the loans and ultimately foreclose on the project, our loss would be approximately $500 million as of December 31, 2004. As new information becomes available or future material developments occur, we will reassess our carrying value of this investment.

      MTBE. In compliance with the 1990 amendments to the Clean Air Act, we used the gasoline additive methyl tertiary-butyl ether (MTBE) in some of our gasoline. We have also produced, bought, sold and distributed MTBE. A number of lawsuits have been filed throughout the U.S. regarding MTBE’s potential impact on water supplies. We and some of our subsidiaries are among the defendants in over 60 such lawsuits. As a result of a ruling issued on March 16, 2004, these suits have been or are in the process of being consolidated for pre-trial purposes in multi-district litigation in the U.S. District Court for the Southern District of New York. The plaintiffs, certain state attorneys general and various water districts, seek remediation of their groundwater, prevention of future contamination, a variety of compensatory damages, punitive damages, attorney’s fees, and court costs. Our costs and legal exposure related to these lawsuits are not currently determinable.

      Wise Arbitration. William Wise, our former Chief Executive Officer, initiated an arbitration proceeding alleging that we breached employment and other agreements by failing to make certain payments to him following his departure from El Paso in 2003. Discovery is underway, with a hearing scheduled in the summer of 2005.

Government Investigations

      Power Restructuring. In October 2003, we announced that the SEC had authorized the staff of the Fort Worth Regional Office to conduct an investigation of certain aspects of our periodic reports filed with the SEC. The investigation appears to be focused principally on our power plant contract restructurings and the related disclosures and accounting treatment for the restructured power contracts, including in particular the Eagle Point restructuring transaction completed in 2002. We have cooperated with the SEC investigation.

      Wash Trades. In June 2002, we received an informal inquiry from the SEC regarding the issue of round trip trades. Although we do not believe any round trip trades occurred, we submitted data to the SEC in July 2002. In July 2002, we received a federal grand jury subpoena for documents concerning round trip or wash trades. We have complied with those requests. We have also cooperated with the U.S. Attorney regarding an investigation of specific transactions executed in connection with hedges of our natural gas and oil production and the restatement of such hedges.

      Price Reporting. In October 2002, the FERC issued data requests regarding price reporting of transactional data to the energy trade press. We provided information to the FERC, the Commodity Futures Trading Commission (CFTC) and the U.S. Attorney in response to their requests. In the first quarter of 2003, we announced a settlement with the CFTC of the price reporting matter providing for the payment of a civil monetary penalty by EPM of $20 million, $10 million of which is payable in 2006, without admitting or denying the CFTC holdings in the order. We are continuing to cooperate with the U.S. Attorney’s investigation of this matter.

      Reserve Revisions. In March 2004, we received a subpoena from the SEC requesting documents relating to our December 31, 2003 natural gas and oil reserve revisions. We have also received federal grand

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jury subpoenas for documents with regard to these reserve revisions. We are cooperating with the SEC’s and the U.S. Attorney’s investigations of this matter.

      Storage Reporting. In November 2004, ANR and TGP received a data request from the FERC in connection with its investigation into the weekly storage withdrawal number reported by the Energy Information Administration (EIA) for the eastern region on November 24, 2004, that was subsequently revised downward by the EIA. Specifically, ANR and TGP provided information on their weekly EIA submissions for two weeks in November 2004. Neither ANR nor TGP’s submissions to the EIA were revised subsequent to their original submissions. Although ANR made a correction to one daily posting on its electronic bulletin board during this period, those postings are unrelated to EIA submissions. In December 2004, ANR received a similar data request from the CFTC and ANR provided the requested information. On December 17, 2004, the FERC held a press conference in which they disclosed that their inquiry had determined that an unaffiliated third party was the source of the downward revision.

      Iraq Oil Sales. In September 2004, The Coastal Corporation (now known as El Paso CGP Company, which we acquired in January 2001) received a subpoena from the grand jury of the U.S. District Court for the Southern District of New York to produce records regarding the United Nations’ Oil for Food Program governing sales of Iraqi oil. The subpoena seeks various records relating to transactions in oil of Iraqi origin during the period from 1995 to 2003. In November 2004, we received an order from the SEC to provide a written statement in connection with Coastal and El Paso’s participation in the Oil for Food Program. We have also received informal requests for information and documents from the United States Senate’s Permanent Subcommittee of Investigations and the House of Representatives International Relations Committee related to Coastal’s purchases of Iraqi crude under the Oil for Food Program. We are cooperating with the U.S. Attorney’s, the SEC’s, the Senate Subcommittee’s, and the House Committee’s investigations of this matter.

      Carlsbad. In August 2000, a main transmission line owned and operated by EPNG ruptured at the crossing of the Pecos River near Carlsbad, New Mexico. Twelve individuals at the site were fatally injured. In June 2001, the U.S. Department of Transportation’s Office of Pipeline Safety issued a Notice of Probable Violation and Proposed Civil Penalty to EPNG. The Notice alleged five violations of DOT regulations, proposed fines totaling $2.5 million and proposed corrective actions. EPNG has fully accrued for these fines. In October 2001, EPNG filed a response with the Office of Pipeline Safety disputing each of the alleged violations. In December 2003, the matter was referred to the Department of Justice.

      After a public hearing conducted by the National Transportation Safety Board (NTSB) on its investigation into the Carlsbad rupture, the NTSB published its final report in April 2003. The NTSB stated that it had determined that the probable cause of the August 2000 rupture was a significant reduction in pipe wall thickness due to severe internal corrosion, which occurred because EPNG’s corrosion control program “failed to prevent, detect, or control internal corrosion” in the pipeline. The NTSB also determined that ineffective federal preaccident inspections contributed to the accident by not identifying deficiencies in EPNG’s internal corrosion control program.

      In November 2002, EPNG received a federal grand jury subpoena for documents related to the Carlsbad rupture and cooperated fully in responding to the subpoena. That subpoena has since expired. In December 2003 and January 2004, eight current and former employees were served with testimonial subpoenas issued by the grand jury. Six individuals testified in March 2004. In April 2004, we and EPNG received a new federal grand jury subpoena requesting additional documents. We have responded fully to this subpoena. Two additional employees testified before the grand jury in June 2004.

      A number of civil actions were filed against EPNG in connection with the rupture which have now been settled or should be fully covered by insurance.

      In addition to the above matters, we and our subsidiaries and affiliates are named defendants in numerous lawsuits and governmental proceedings that arise in the ordinary course of our business. There are also other regulatory rules and orders in various stages of adoption, review and/or implementation, none of which we believe will have a material impact on us.

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Rates and Regulatory Matters

      Pipeline Integrity Costs. In November 2004, the FERC issued a proposed accounting release that may impact certain costs our interstate pipelines incur related to their pipeline integrity programs. If the release is enacted as written, we would be required to expense certain future pipeline integrity costs instead of capitalizing them as part of our property, plant and equipment. Although we continue to evaluate the impact of this potential accounting release, we currently estimate that if the release is enacted as written, we would be required to expense an additional amount of pipeline integrity expenditures in the range of approximately $25 million to $41 million annually over the next eight years.

      Inquiry Regarding Income Tax Allowances. In December 2004, the FERC issued a Notice of Inquiry (NOI) in response to a recent D.C. Circuit decision that held the FERC had not adequately justified its policy of providing a certain oil pipeline limited partnership with an income tax allowance equal to the proportion of its limited partnership interests owned by corporate partners. The FERC sought comments on whether the court’s reasoning should be applied to other partnerships or other ownership structures. We own interests in non-taxable entities that could be affected by this ruling. We cannot predict what impact this inquiry will have on our interstate pipelines, including those pipelines which are jointly owned with unaffiliated parties.

      Selective Discounting Notice of Inquiry. In November 2004, the FERC issued a NOI seeking comments on its policy regarding selective discounting by natural gas pipelines. The FERC seeks comments regarding whether its practice of permitting pipelines to adjust their ratemaking throughput downward in rate cases to reflect discounts given by pipelines for competitive reasons is appropriate when the discount is given to meet competition from another natural gas pipeline. Our pipelines filed comments on the NOI. Neither the final outcome of this inquiry nor the impact on our pipelines can be predicted with certainty.

Other Contingencies

      Enron Bankruptcy. In December 2001, Enron Corp. and a number of its subsidiaries, including Enron North America Corp. (ENA) and Enron Power Marketing, Inc. (EPMI) filed for Chapter 11 bankruptcy protection in New York. We had various contracts with Enron marketing and trading entities, and most of the trading-related contracts were terminated due to the bankruptcy. In October 2002, we filed proofs of claims against the Enron trading entities totaling approximately $317 million.

      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.

      Brazilian Matters. We own a number of interests in various production properties, power and pipeline assets in Brazil. Our total investment in Brazil was approximately $1.6 billion as of December 31, 2004.

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Although economic conditions have generally improved over the last year, Brazil has experienced high interest rates on local debt and has experienced restrictions on the availability of foreign funds and investment. In addition, in a number of our assets and investments, Petrobras either serves as a joint owner, a customer or a shipper to the asset or project. Although we have no material current disputes with Petrobras with regard to the ownership or operation of our production and pipeline assets, current disputes on the Macae power plant between us and Petrobras may negatively impact these investments and the impact could be material. We also own an investment in a power plant in Brazil called Porto Velho. The Porto Velho project is in the process of negotiating certain provisions of its PPAs with Eletronorte, including the amount of installed capacity, energy prices, take or pay levels, the term of the first PPA and other issues. In addition, in October 2004, the project experienced an outage with a steam turbine which resulted in a partial reduction in the plant’s capacity. The project expects to replace or repair the steam turbine by the first quarter of 2006. We are uncertain what impact this outage will have on the PPAs. Although the current terms of the PPAs and the proposed amendments do not indicate an impairment of our investment, we may be required to write down the value of our investment if these negotiations are resolved unfavorably. Our investment in Porto Velho was $292 million at December 31, 2004.

      For each of our outstanding legal and other contingent matters, we evaluate the merits of the item, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, then we establish the necessary accruals. While the outcome of these matters cannot be predicted with certainty and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, we believe we have established appropriate reserves for these matters. However, it is possible that new information or future developments could require us to reassess our potential exposure related to these matters and adjust our accruals accordingly. As of December 31, 2004, we had approximately $592 million net of related insurance receivables accrued for our outstanding legal and other contingencies, including amounts accrued for our Western Energy Settlement.

Environmental Matters

      We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. As of December 31, 2004, we had accrued approximately $380 million, including approximately $373 million for expected remediation costs and associated onsite, offsite and groundwater technical studies, and approximately $7 million for related environmental legal costs, which we anticipate incurring through 2027. Of the $380 million accrual, $100 million was reserved for facilities we currently operate, and $280 million was reserved for non-operating sites (facilities that are shut down or have been sold) and Superfund sites.

      Our reserve estimates range from approximately $380 million to approximately $547 million. Our accrual represents a combination of two estimation methodologies. First, where the most likely outcome can be reasonably estimated, that cost has been accrued ($82 million). Second, where the most likely outcome cannot be estimated, a range of costs is established ($298 million to $465 million) and if no one amount in that range is more likely than any other, the lower end of the expected range has been accrued. By type of site, our reserves are based on the following estimates of reasonably possible outcomes.

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

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      Below is a reconciliation of our accrued liability from January 1, 2004, to December 31, 2004 (in millions):

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

      For 2005, we estimate that our total remediation expenditures will be approximately $64 million. In addition, we expect to make capital expenditures for environmental matters of approximately $62 million in the aggregate for the years 2005 through 2009. These expenditures primarily relate to compliance with clean air regulations.

      Internal PCB Remediation Project. Since 1988, TGP, our subsidiary, has been engaged in an internal project to identify and address the presence of polychlorinated biphenyls (PCBs) and other substances, including those on the EPA List of Hazardous Substances (HSL), at compressor stations and other facilities it operates. While conducting this project, TGP has been in frequent contact with federal and state regulatory agencies, both through informal negotiation and formal entry of consent orders. TGP executed a consent order in 1994 with the EPA, governing the remediation of the relevant compressor stations, and is working with the EPA and the relevant states regarding those remediation activities. TGP is also working with the Pennsylvania and New York environmental agencies regarding remediation and post-remediation activities at its Pennsylvania and New York stations.

      PCB Cost Recoveries. In May 1995, following negotiations with its customers, TGP filed an agreement with the FERC that established a mechanism for recovering a substantial portion of the environmental costs identified in its internal remediation project. The agreement, which was approved by the FERC in November 1995, provided for a PCB surcharge on firm and interruptible customers’ rates to pay for eligible remediation costs, with these surcharges to be collected over a defined collection period. TGP has received approval from the FERC to extend the collection period, which is now currently set to expire in June 2006. The agreement also provided for bi-annual audits of eligible costs. As of December 31, 2004, TGP had pre-collected PCB costs by approximately $125 million. This pre-collected amount will be reduced by future eligible costs incurred for the remainder of the remediation project. To the extent actual eligible expenditures are less than the amounts pre-collected, TGP will refund to its customers the difference, plus carrying charges incurred up to the date of the refunds. As of December 31, 2004, TGP has recorded a regulatory liability (included in other non-current liabilities on its balance sheet) of $97 million for estimated future refund obligations.

      CERCLA Matters. We have received notice that we could be designated, or have been asked for information to determine whether we could be designated, as a Potentially Responsible Party (PRP) with respect to 61 active sites under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) or state equivalents. We have sought to resolve our liability as a PRP at these sites through indemnification by third-parties and settlements which provide for payment of our allocable share of remediation costs. As of December 31, 2004, we have estimated our share of the remediation costs at these sites to be between $31 million and $52 million. Since the clean-up costs are estimates and are subject to revision as more information becomes available about the extent of remediation required, and because in some cases we have asserted a defense to any liability, our estimates could change. Moreover, liability under the federal CERCLA statute is joint and several, meaning that we could be required to pay in excess of our pro rata share of remediation costs. Our understanding of the financial strength of other PRPs has been considered, where appropriate, in estimating our liabilities. Accruals for these issues are included in the previously indicated estimates for Superfund sites.

      It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. We may incur significant costs and liabilities in order to comply with existing environmental laws and regulations. It is also possible that other developments, such as

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increasingly strict environmental laws and regulations and claims for damages to property, employees, other persons and the environment resulting from our current or past operations, could result in substantial costs and liabilities in the future. As this information becomes available, or other relevant developments occur, we will adjust our accrual amounts accordingly. While there are still uncertainties relating to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our current environmental reserves are adequate.

Commitments and Purchase Obligations

      Operating Leases. We maintain operating leases in the ordinary course of our business activities. These leases include those for office space and operating facilities and office and operating equipment, and the terms of the agreements vary from 2005 until 2053. As of December 31, 2004, our total commitments under operating leases were approximately $442 million. Minimum annual rental commitments under our operating leases at December 31, 2004, were as follows:

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

      Aggregate minimum commitments have not been reduced by minimum sublease rentals of approximately $28 million due in the future under noncancelable subleases. Rental expense on our operating leases for the years ended December 31, 2004, 2003 and 2002 was $101 million, $113 million and $116 million.

      In May 2004, we announced we would consolidate our Houston-based operations into one location. This consolidation was substantially completed by the end of 2004. As a result, as of December 31, 2004 we have established an accrual totaling $80 million to record the liability, net of sublease rentals, for our obligations under our existing lease terms. We currently lease approximately 888,000 square feet of office space in the buildings we are vacating under various leases with lease terms expiring through 2014. See Note 4 for additional information regarding these lease terminations.

      Guarantees. We are involved in various joint ventures and other ownership arrangements that sometimes require additional financial support that results in the issuance of financial and performance guarantees. In a financial guarantee, we are obligated to make payments if the guaranteed party fails to make payments under, or violates the terms of, the financial arrangement. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. If they do not, we are required to perform on their behalf. We also periodically provide indemnification arrangements related to assets or businesses we have sold. These arrangements include indemnification for income taxes, the resolution of existing disputes, environmental matters, and necessary expenditures to ensure the safety and integrity of the assets sold.

      We evaluate at the time a guarantee or indemnity arrangement is entered into and in each period thereafter whether a liability exists and, if so, if it can be estimated. We record accruals when both these criteria are met. As of December 31, 2004, we had accrued $70 million related to these arrangements. As of December 31, 2004, we had approximately $40 million of financial and performance guarantees, and indemnification arrangements not otherwise reflected in our financial statements.

      Other Commercial Commitments. We have various other commercial commitments and purchase obligations that are not recorded on our balance sheet. At December 31, 2004, we had firm commitments under tolling, transportation and storage capacity contracts of $1.5 billion, commodity purchase commitments

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of $149 million and other purchase and capital commitments (including maintenance, engineering, procurement and construction contracts) of $224 million.

18. Retirement Benefits

  Pension Benefits

      Our primary pension plan is a defined benefit plan that covers substantially all of our U.S. employees and provides benefits under a cash balance formula. Certain employees who participated in the prior pension plans of El Paso, Sonat or Coastal receive the greater of cash balance benefits or transition benefits under the prior plan formulas. Transition benefits reflect prior plan accruals for these employees through December 31, 2001, December 31, 2004 and March 31, 2006. We do not anticipate making any contributions to this pension plan in 2005.

      In addition to our primary pension plan, we maintain a Supplemental Executive Retirement Plan (SERP) that provides additional benefits to selected officers and key management. The SERP provides benefits in excess of certain IRS limits that essentially mirror those in the primary pension plan. We also maintain two other pension plans that are closed to new participants which provide benefits to former employees of our previously discontinued coal and convenience store operations. The SERP and the frozen plans together are referred to below as other pension plans. We also participate in one multi-employer pension plan for the benefit of our former employees who were union members. Our contributions to this plan during 2004, 2003 and 2002 were not material. We expect to contribute $5 million to the SERP in 2005. We do not anticipate making any contributions to our other pension plans in 2005.

      During 2004, we recognized a $4 million curtailment benefit in our pension plans primarily related to a reduction in the number of employees that participate in our pension plan, which resulted from our various asset sales and employee severance efforts. During 2003, we recognized $11 million in charges in our pension plans that resulted from employee terminations and our internal reorganization.

  Retirement Savings Plan

      We maintain a defined contribution plan covering all of our U.S. employees. Prior to May 1, 2002, we matched 75 percent of participant basic contributions up to 6 percent, with the matching contributions being made to the plan’s stock fund, which participants could diversify at any time. After May 1, 2002, the plan was amended to allow for company matching contributions to be invested in the same manner as that of participant contributions. Effective March 1, 2003, we suspended the matching contributions, but reinstituted it again at a rate of 50 percent of participant basic contributions up to 6 percent on July 1, 2003. Effective July 1, 2004, we increased the matching contributions to 75 percent of participant basic contributions up to 6 percent. Amounts expensed under this plan were approximately $16 million, $14 million and $28 million for the years ended December 31, 2004, 2003 and 2002.

  Other Postretirement Benefits

      We provide postretirement medical benefits for closed groups of retired employees and limited postretirement life insurance benefits for current and retired employees. Other postretirement employee benefits (OPEB) for our regulated pipeline companies are prefunded to the extent such costs are recoverable through rates. To the extent actual OPEB costs for our regulated pipeline companies differ from the amounts recovered in rates, a regulatory asset or liability is recorded. We expect to contribute $63 million to our postretirement plans in 2005. Medical benefits for these closed groups of retirees may be subject to deductibles, co-payment provisions, and other limitations and dollar caps on the amount of employer costs, and we reserve the right to change these benefits.

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      Below is our projected benefit obligation, accumulated benefit obligation, fair value of plan assets as of September 30, our plan measurement date, and related balance sheet accounts for our pension plans as of December 31:

	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

      Below is information for our pension plans that have accumulated benefit obligations in excess of plan assets for the year ended December 31:

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

      We are required to recognize an additional minimum liability for pension plans with an accumulated benefit obligation in excess of plan assets. We recorded other comprehensive income (loss) of $(33) million in 2004 and $18 million in 2003 related to the change in this additional minimum liability.

      Below is the change in projected benefit obligation, change in plan assets and reconciliation of funded status for our pension and other postretirement benefit plans. Our benefits are presented and computed as of and for the twelve months ended September 30.

								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

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								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.

     The portion of our other postretirement benefit obligation included in current liabilities was $38 million and $45 million as of December 31, 2004 and 2003.

      Future benefits expected to be paid from our pension plans and our other postretirement plans as of December 31, 2004, are as follows:

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.

     For each of the years ended December 31, the components of net benefit cost (income) are as follows:

											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

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⁽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.

     Projected benefit obligations and net benefit cost are based on actuarial estimates and assumptions. The following table details the weighted-average actuarial assumptions used in determining the projected benefit obligation and net benefit costs of our pension and other postretirement plans for 2004, 2003 and 2002:

								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.

     Actuarial estimates for our other postretirement benefit plans assumed a weighted-average annual rate of increase in the per capita costs of covered health care benefits of 10.0 percent in 2004, gradually decreasing to 5.5 percent by the year 2009. Assumed health care cost trends have a significant effect on the amounts reported for other postretirement benefit plans. A one-percentage point change in assumed health care cost trends would have the following effects as of September 30:

		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	)

     Plan Assets

      The following table provides the target and actual asset allocations in our pension and other postretirement benefit plans as of September 30:

		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.

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     The primary investment objective of our plans is to ensure, that over the long-term life of the plans, an adequate pool of sufficiently liquid assets to support the benefit obligations to participants, retirees and beneficiaries exists. In meeting this objective, the plans seek to achieve a high level of investment return consistent with a prudent level of portfolio risk. Investment objectives are long-term in nature covering typical market cycles of three to five years. Any shortfall of investment performance compared to investment objectives is the result of general economic and capital market conditions.

      In 2003, we modified our target asset allocations for our other postretirement benefit plans to increase our equity allocation to 65 percent of total plan assets and as a result, the actual assets as of September 30, 2004 were close to our targets. During 2004, we modified our target and actual asset allocations for our pension plans to reduce our equity allocation to 60 percent of total plan assets. Correspondingly, our 2005 assumption related to the expected return on plan assets were reduced from 8.5 percent to 8.0 percent to reflect this change.

19. Capital Stock

     Common Stock

      In 2003 and 2004, we issued 26.4 million shares to satisfy our obligations under the Western Energy Settlement (See Note 17). In 2003, we also issued 15 million shares as part of an offer to exchange our equity security units for common stock (see Note 15).

     Dividend

      For the year ended December 31, 2004, we paid dividends of $101 million to common stockholders. On February 18, 2005, we declared quarterly dividends of $0.04 per share on our common stock, payable on April 4, 2005 to the shareholders of record on March 4, 2005. The dividends on our common stock were treated as a reduction of paid-in-capital since we currently have an accumulated deficit.

      El Paso Tennessee Pipeline Co., our subsidiary, pays dividends of approximately $6 million each quarter on its Series A cumulative preferred stock, which is 8.25 percent per annum (2.0625 percent per quarter).

20. Stock-Based Compensation

      We grant stock awards under various stock option plans. We account for our stock option plans using Accounting Principles Board Opinion No. 25 and its related interpretations. Under our employee plans, we may issue incentive stock options on our common stock (intended to qualify under Section 422 of the Internal Revenue Code), non-qualified stock options, restricted stock, stock appreciation rights, phantom stock options, and performance units. Under our non-employee director plan, we may issue deferred shares of common stock. We have reserved approximately 68 million shares of common stock for existing and future stock awards, including deferred shares. As of December 31, 2004, approximately 28 million shares remained unissued.

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     Non-qualified Stock Options

      We granted non-qualified stock options to our employees in 2004, 2003 and 2002. Our stock options have contractual terms of 10 years and generally vest after completion of one to five years of continuous employment from the grant date. Prior to 2004, we also granted options to non-employee members of the Board of Directors at fair market value on the grant date that were exercisable immediately. A summary of our stock option transactions, stock options outstanding and stock options exercisable as of December 31 is presented below:

		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.

     The following table summarizes the range of exercise prices and the weighted-average remaining contractual life of options outstanding and the range of exercise prices for the options exercisable at December 31, 2004.

	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

      The fair value of each stock option granted used to complete pro forma net income disclosures (see Note 1) is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions:

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%

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  Restricted Stock

      Under our stock-based compensation plans, a limited number of shares of restricted common stock may be granted to our officers and employees. These shares carry voting and dividend rights; however, sale or transfer of the shares is restricted. These restricted stock awards vest over a specific period of time and/or if we achieve established performance targets. Restricted stock awards representing 3.1 million, 0.4 million, and 1.4 million shares were granted during 2004, 2003 and 2002 with a weighted-average grant date fair value of $8.63, $7.46 and $38.45 per share. At December 31, 2004, 3.9 million shares of restricted stock were outstanding. The value of restricted shares subject to performance vesting is determined based on the fair market value on the date performance targets are achieved, and this value is charged to compensation expense ratably over the required service or restriction period. The value of time vested restricted shares is determined at their issuance date and this cost is amortized to compensation expense over the vesting period. For 2004, 2003 and 2002, these charges totaled $23 million, $60 million and $73 million. We have $20 million on our balance sheet as of December 31, 2004 related to unamortized compensation that will be charged to expense over the vesting period of the restricted stock.

  Performance Units

      In the past, we awarded eligible officers performance units that were payable in cash or stock at the end of the vesting period. The final value of the performance units varied according to the plan under which they were granted, but was usually based on our common stock price at the end of the vesting period or total shareholder return during the vesting period relative to our peer group. The value of the performance units was charged ratably to compensation expense over the vesting period with periodic adjustments to account for the fluctuation in the market price of our stock or changes in expected total shareholder return. We recorded a credit to compensation expense in 2002 of $11 million upon the reduction of our performance unit liability by $21 million due to a reduction in our expected total shareholder return. In July 2003, all outstanding performance units vested at the “Below Threshold” level and the Compensation Committee of our Board of Directors determined that there would be no payout for the performance units. Accordingly, we reversed the remaining liability for these units and recorded income of $16 million.

     Employee Stock Purchase Program

      In October 1999, we implemented an employee stock purchase plan under Section 423 of the Internal Revenue Code. The plan allowed participating employees the right to purchase our common stock on a quarterly basis at 85 percent of the lower of the market price at the beginning or at the end of each calendar quarter. Five million shares of common stock are authorized for issuance under this plan. For the year ended December 31, 2002, we sold 1.4 million shares of our common stock to our employees. Effective January 1, 2003, we suspended our employee stock purchase program.

21.  Business Segment Information

      During 2004, we reorganized our business structure into two primary business lines, regulated and non-regulated, and modified our operating segments. Historically, our operating segments included Pipelines, Production, Merchant Energy and Field Services. As a result of this reorganization, we eliminated our Merchant Energy segment and established individual Power and Marketing and Trading segments. All periods presented reflect this change in segments. Our regulated business consists of our Pipelines segment, while our non-regulated businesses consist of our Production, Marketing and Trading, Power, and Field Services segments. Our segments are strategic business units that provide a variety of energy products and services. They are managed separately as each segment requires different technology and marketing strategies. Our corporate operations include our general and administrative functions as well as a telecommunications business, and various other contracts and assets, all of which are immaterial. These other assets and contracts include financial services, LNG and related items.

      During the first quarter of 2004, we reclassified our petroleum ship charter operations from discontinued operations to continuing corporate operations. During the second quarter of 2004, we reclassified our Canadian

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and certain other international natural gas and oil production operations from our Production segment to discontinued operations. Our operating results for all periods presented reflect these changes.

      Our Pipelines segment provides natural gas transmission, storage, and related services, primarily in the U.S. We conduct our activities primarily through eight wholly owned and four partially owned interstate transmission systems along with five underground natural gas storage entities and an LNG terminalling facility.

      Our Production segment is engaged in the exploration for and the acquisition, development and production of natural gas, oil and natural gas liquids, primarily in the United States and Brazil. In the U.S., Production has onshore operations and properties in 20 states and offshore operations and properties in federal and state waters in the Gulf of Mexico.

      Our Marketing and Trading segment’s operations focus on the marketing of our natural gas and oil production and the management of our remaining trading portfolio.

      Our Power segment owns and has interests in domestic and international power assets. As of December 31, 2004, our power segment primarily consisted of an international power business. Historically, this segment also had domestic power plant operations and a domestic power contract restructuring business. We have sold or announced the sale of substantially all of these domestic businesses. Our ongoing focus within the power segment will be to maximize the value of our assets in Brazil.

      Our Field Services segment conducts midstream activities related to our remaining gathering and processing assets.

      We had no customers whose revenues exceeded 10 percent of our total revenues in 2004, 2003 and 2002.

      We use earnings before interest expense and income taxes (EBIT) to assess the operating results and effectiveness of our business segments. We define EBIT as net income (loss) adjusted for (i) items that do not impact our income (loss) from continuing operations, such as extraordinary items, discontinued operations and the impact of accounting changes, (ii) income taxes, (iii) interest and debt expense and (iv) distributions on preferred interests of consolidated subsidiaries. Our business operations consist of both consolidated businesses as well as substantial investments in unconsolidated affiliates. We believe EBIT is useful to our investors because it allows them to more effectively evaluate the performance of all of our businesses and investments. Also, we exclude interest and debt expense and distributions on preferred interests of consolidated subsidiaries so that investors may evaluate our operating results without regard to our financing methods or capital structure. EBIT may not be comparable to measures used by other companies. Additionally, EBIT should be considered in conjunction with net income and other performance measures such as operating income or operating cash flow. Below is a reconciliation of our EBIT to our income (loss) from continuing operations for the three years ended December 31:

								2002
		2004			2003			(Restated)
		(In millions)
Total EBIT		$	855		$	769		$	(427	)
Interest and debt expense			(1,607	)		(1,791	)		(1,297	)
Distributions on preferred interests of consolidated subsidiaries			(25	)		(52	)		(159	)
Income taxes			(25	)		551			641
	Loss from continuing operations	$	(802	)	$	(523	)	$	(1,242	)

156

’

      The following tables reflect our segment results as of and for each of the three years ended December 31:

		Segments
		As of or for the Year Ended December 31, 2004
		Regulated			Non-regulated
								Marketing						Field
		Pipelines			Production			and Trading			Power			Services			Corporate(1)			Total
		(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			—			583			508			(6	)		1,092
Operating income (loss)		$	1,129		$	726		$	(562	)	$	(408	)	$	(465	)	$	(214	)	$	206
Earnings from unconsolidated affiliates			173			4			—			(236	)		618			—			559
Other income			33			4			15			84			2			51			189
Other expense			(4	)		—			—			(9	)		(35	)		(51	)		(99	)
EBIT		$	1,331		$	734		$	(547	)	$	(569	)	$	120		$	(214	)	$	855
Discontinued operations, net of income taxes		$	—		$	(76	)	$	—		$	—		$	—		$	(70	)	$	(146	)
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 of $308 million. Our intersegment revenues, along with our intersegment operating expenses, were incurred in the normal course of business between our operating segments. We record an intersegment revenue and 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).
(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.

157

		Segments
		As of or for the Year Ended December 31, 2003
		Regulated			Non-regulated
								Marketing						Field
		Pipelines			Production			and Trading			Power			Services			Corporate(1)			Total
		(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		$	—		$	(93	)	$	—		$	—		$	—		$	(1,303	)	$	(1,396	)
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			3,889			31,555
	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 of $316 million. Our intersegment revenues, along with our intersegment operating expenses, were incurred in the normal course of business between our operating segments. We record an intersegment revenue and 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).
(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).

158

		Segments
		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 of $213 million. Our intersegment revenues, along with our intersegment operating expenses, were incurred in the normal course of business between our operating segments. We record an intersegment revenue and 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).
(5)	Amounts are net of third party reimbursements of our capital expenditures and returns of invested capital.

159

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

      We hold investments in various unconsolidated affiliates which are accounted for using the equity method of accounting. Our principal equity method investees are international pipelines, interstate pipelines, power generation plants, and gathering systems. Our investment balance was less than our equity in the net assets of these investments by $265 million and $136 million as of December 31, 2004 and 2003. These differences primarily relate to unamortized purchase price adjustments, net of asset impairment charges. Our net ownership interest, investments in and earnings (losses) from our unconsolidated affiliates are as follows as of and for the year ended December 31:

													Earnings from
			Net Ownership						Investment				Unconsolidated Affiliates
			Interest
											2003								2002
			2004			2003			2004		(Restated)		2004			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		(14	)		18			33
		Total foreign								1,080		1,253		(46	)		147			(285	)
Total investments in unconsolidated affiliates									$	2,614	$	3,409
Total earnings (losses) from unconsolidated affiliates													$	559		$	362		$	(214	)

160

(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 165.
(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.

161

     Our impairment charges and gains and losses on sales of equity investments that are included in earnings (losses) from unconsolidated affiliates during 2004, 2003 and 2002 consisted of the following:

		Pre-tax
Investment		Gain (Loss)			Cause of Impairments or Gain (Loss)
		(In millions)
2004
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			7
	Total	$	129
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 165.
(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.

162

(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.

     Below is summarized financial information of our proportionate share of unconsolidated affiliates. This information includes affiliates in which we hold a less than 50 percent interest as well as those in which we hold a greater than 50 percent interest. We received distributions and dividends of $358 million and $398 million in 2004 and 2003, which includes $23 million and $53 million of returns of capital, from our investments. Our proportional shares of the unconsolidated affiliates in which we hold a greater than 50 percent interest had net income of $15 million, $119 million and $26 million in 2004, 2003 and 2002 and total assets of $734 million and $1.1 billion as of December 31, 2004 and 2003.

		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

Below is summarized financial information of GulfTerra (in millions):

		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

163

      The following table shows revenues and charges resulting from transactions with our unconsolidated affiliates:

	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

      As of December 31, 2002, we held equity investments in Chaparral and Gemstone. During 2003, we acquired the remaining third party equity interests and all of the voting rights in both of these entities. As discussed in Note 2, we consolidated Chaparral effective January 1, 2003 and Gemstone effective April 1, 2003.

GulfTerra

      Prior to the sale of our interests in GulfTerra on September 30, 2004, our Field Services segment managed GulfTerra’s daily operations and performed all of GulfTerra’s administrative and operational activities under a general and administrative services agreement or, in some cases, separate operational agreements. GulfTerra contributed to our income through our general partner interest and our ownership of common and preference units. We did not have any loans to or from GulfTerra.

      In December 2003, GulfTerra and a wholly owned subsidiary of Enterprise executed definitive agreements to merge to form the second largest publicly traded energy partnership in the U.S. On July 29, 2004, GulfTerra’s unitholders approved the adoption of its merger agreement with Enterprise which was completed in September 2004. In January 2005, we sold our remaining 9.9 percent interest in the two percent general partner of Enterprise and approximately 13.5 million common units in Enterprise for $425 million. We also sold our membership interest in two subsidiaries that own and operate natural gas gathering systems and the Indian Springs processing facility to Enterprise for $75 million.

      In the December 2003 sales transactions, specific evaluation procedures were instituted to ensure that they were in the best interests of us and the partnership and were based on fair values. These procedures required our Board of Directors to evaluate and approve, as appropriate, each transaction with GulfTerra. In addition, a special committee comprised of the GulfTerra general partner’s independent directors evaluated the transactions on GulfTerra’s behalf. Both boards engaged independent financial advisors to assist with the evaluation and to opine on its fairness.

164

      Below is a detail of the gains or losses recognized in earnings from unconsolidated affiliates on transactions related to GulfTerra/Enterprise and other significant transactions during 2002, 2003, and 2004:

					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.

     Prior to the sale of our interests in GulfTerra to Enterprise in September 2004, a subsidiary in our Field Services segment served as the general partner of GulfTerra, a publicly traded master limited partnership. We had the following interests in GulfTerra (Enterprise effective September 30, 2004) as of December 31:

		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.

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     During each of the three years ended December 31, 2004, we conducted the following transactions with GulfTerra:

		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

  Contingent Matters that Could Impact Our Investments

      Economic Conditions in the Dominican Republic. We have investments in power projects in the Dominican Republic with an aggregate exposure of approximately $103 million. We own an approximate 25 percent ownership interest in a 416 MW power generating complex known as Itabo. We also own an approximate 48 percent interest in a 67 MW heavy fuel oil fired power project known as the CEPP project. In 2003, an economic crisis developed in the Dominican Republic resulting in a significant devaluation of the Dominican peso. As a consequence of economic conditions described above, combined with the high prices on imported fuels and due to their inability to pass through these high fuel costs to their consumers, the local distribution companies that purchase the electrical output of these facilities have been delinquent in their payments to CEPP and Itabo, and to the other generating facilities in the Dominican Republic since April 2003. The failure to pay generators has resulted in the inability of the generators to purchase fuel required to produce electricity resulting in significant energy shortfalls in the country. In addition, a recent local court decision has resulted in the potential inability of CEPP to continue to receive payments for its power sales which may affect CEPP’s ability to operate. We are contesting the local court decision. We continue to monitor the economic and regulatory situation in the Dominican Republic and as new information becomes available or future material developments arise, it is possible that impairments of these investments may occur.

      Berkshire Power Project. We own a 56 percent direct equity interest in a 261 MW power plant, Berkshire Power, located in Massachusetts. We supply natural gas to Berkshire under a fuel management agreement. Berkshire has the ability to delay payment of 33 percent of the amounts due to us under the fuel supply agreement, up to a maximum of $49 million, if Berkshire does not have available cash to meet its debt service requirements. Berkshire has delayed a total of $46 million of its fuel payments, including $8 million of interest, under this agreement as of December 31, 2004. During 2002, Berkshire’s lenders asserted that Berkshire was in default on its loan agreement, and these issues remain unresolved. Based on the uncertainty surrounding these negotiations and Berkshire’s inability to generate adequate future cash flow, we recorded losses of $10 million and $28 million in 2004 and 2003 associated with the amounts due to us under the fuel supply agreement.

      For contingent matters that could impact our investments in Brazil, see Note 17.

      For a discussion of non-recourse project financing, see Note 15.

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      Duke Litigation. Citrus Trading Corporation (CTC), a direct subsidiary of Citrus Corp. (Citrus) has filed suit against Duke Energy LNG Sales, Inc (Duke) and PanEnergy Corp., the holding company of Duke, seeking damages of $185 million for breach of a gas supply contract and wrongful termination of that contract. Duke sent CTC notice of termination of the gas supply contract alleging failure of CTC to increase the amount of an outstanding letter of credit as collateral for its purchase obligations. Duke has filed in federal court an amended counter claim joining Citrus and a cross motion for partial summary judgment, requesting that the court find that Duke had a right to terminate its gas sales contract with CTC due to the failure of CTC to adjust the amount of the letter of credit supporting its purchase obligations. CTC filed an answer to Duke’s motion, which is currently pending before the court. An unfavorable outcome on this matter could impact the value of our investment in Citrus.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
El Paso Corporation:

      We have completed an integrated audit of El Paso Corporation’s 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004 and audits of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated Financial Statements and Financial Statement Schedule

      In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of El Paso Corporation and its subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      As discussed in Note 1, the 2002 consolidated financial statements have been restated.

      As discussed in the notes to the consolidated financial statements, the Company adopted FASB Financial Interpretation No. 46, Consolidation of Variable Interest Entities on January 1, 2004; FASB Staff Position No. 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 on July 1, 2004; Statement of Financial Accounting Standards (SFAS) No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity on July 1, 2003; SFAS No. 143, Accounting for Asset Retirement Obligations and SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities on January 1, 2003; SFAS No. 141, Business Combinations, SFAS No. 142, Goodwill and Other Intangible Assets and SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets on January 1, 2002; DIG Issue No. C-16, Scope Exceptions; applying the Normal Purchases and Sales Exception to Contracts that Combine a Forward Contract and Purchased Option Contract on July 1, 2002 and EITF Issue No. 02-03, Accounting for the Contracts Involved in Energy Trading and Risk Management Activities, Consensus 2, on October 1, 2002.

Internal Control Over Financial Reporting

      Also, we have audited management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that El Paso Corporation did not maintain effective internal control over financial reporting as of December 31, 2004, because the Company did not maintain effective controls over (1) access to financial application programs and data in certain information technology environments, (2) account reconciliations and (3) identification, capture and communication of financial data used in accounting for non-routine transactions or activities. Management’s assessment was based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

      The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our

168

responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit.

      We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

      A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

      Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

      A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. The following material weaknesses have been identified and included in management’s assessment. At December 31, 2004, the Company did not maintain effective control over (1) access to financial applications programs and data, (2) account reconciliations and (3) identification, capture and communication of financial data used in accounting for non-routine transactions or activities. A specific description of these control deficiencies which management concluded are material weaknesses, that existed at December 31, 2004, is discussed below.

      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 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.

      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

169

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.

      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 divestiture of assets. These control deficiencies resulted in the restatement of the 2002 financial statements as reflected in this annual report as well as adjustments to the aforementioned accounts impacting 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.

      These material weaknesses were considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2004 consolidated financial statements, and our opinion regarding the effectiveness of the Company’s internal control over financial reporting does not affect our opinion on those consolidated financial statements.

      In our opinion, management’s assessment that El Paso Corporation did not maintain effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on criteria established in Internal Control — Integrated Framework issued by COSO. Also, in our opinion, because of the effects of the material weaknesses described above on the achievement of the objectives of the control criteria, the Company has not maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established in Internal Control — Integrated Framework issued by COSO.

PricewaterhouseCoopers LLP

Houston Texas

March 25, 2004

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Supplemental Selected Quarterly Financial Information (Unaudited)

      Financial information by quarter, is summarized below.

			Quarters Ended
			March 31			June 30			September 30			December 31			Total
			(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			222			17			582			271			1,092
	Operating income (loss)			205			370			(355	)		(14	)		206
	Income (loss) from continuing operations		$	(97	)	$	45		$	(202	)	$	(548	)	$	(802	)
	Discontinued operations, net of income taxes(1)			(109	)		(29	)		(12	)		4			(146	)
	Net income (loss)		$	(206	)	$	16		$	(214	)	$	(544	)	$	(948	)
	Basic and diluted earnings per common share
		Income (loss) from continuing operations	$	(0.15	)	$	0.07		$	(0.31	)	$	(0.86	)	$	(1.25	)
		Discontinued operations, net of income taxes		(0.17	)		(0.04	)		(0.02	)		0.01			(0.23	)
		Net income (loss)	$	(0.32	)	$	0.03		$	(0.33	)	$	(0.85	)	$	(1.48	)
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		$	(84	)	$	(523	)
	Discontinued operations, net of income taxes(1)			(215	)		(939	)		(41	)		(201	)		(1,396	)
	Cumulative effect of accounting changes, net of income taxes			(9	)		—			—			—			(9	)
	Net income (loss)		$	(431	)	$	(1,236	)	$	24		$	(285	)	$	(1,928	)
	Basic and diluted earnings per common share
		Income (loss) from continuing operations	$	(0.34	)	$	(0.50	)	$	0.11		$	(0.14	)	$	(0.87	)
		Discontinued operations, net of income taxes		(0.36	)		(1.57	)		(0.07	)		(0.33	)		(2.34	)
		Cumulative effect of accounting changes, net of income taxes		(0.02	)		—			—			—			(0.02	)
		Net income (loss)	$	(0.72	)	$	(2.07	)	$	0.04		$	(0.47	)	$	(3.23	)

⁽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 for further discussion).

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Supplemental Natural Gas and Oil Operations (Unaudited)

      Our Production segment is engaged in the exploration for, and the acquisition, development and production of natural gas, oil and natural gas liquids, primarily in the United States and Brazil. In the United States, we have onshore operations and properties in 20 states and offshore operations and properties in federal and state waters in the Gulf of Mexico. All of our proved reserves are in the United States and Brazil. We have excluded information relating to our natural gas and oil operations in Canada, Indonesia and Hungary from the following disclosures. We classified these operations as discontinued operations beginning in the second quarter of 2004 based on our decision to exit these operations.

      Capitalized costs relating to natural gas and oil producing activities and related accumulated depreciation, depletion and amortization were as follows at December 31 (in millions):

			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. 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.

     Costs incurred in natural gas and oil producing activities, whether capitalized or expensed, were as follows at December 31 (in millions):

				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

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				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 178.
(2)	In January 2003, we adopted SFAS No. 143, which is further discussed in Note 1. The cumulative effect of adopting SFAS No. 143 was $3 million.

     The table above includes capitalized internal costs incurred in connection with the acquisition, development and exploration of natural gas and oil reserves of $44 million, $58 million, and $76 million and capitalized interest of $22 million, $19 million and $10 million for the years ended December 31, 2004, 2003 and 2002.

      In our January 1, 2005 reserve report, the amounts estimated to be spent in 2005, 2006 and 2007 to develop our worldwide booked proved undeveloped reserves are $182 million, $251 million and $218 million.

      Presented below is an analysis of the capitalized costs of natural gas and oil properties by year of expenditures that are not being amortized as of December 31, 2004, pending determination of proved reserves (in millions):

		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.

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     Projects presently excluded from amortization are in various stages of evaluation. The majority of these costs are expected to be included in the amortization calculation in the years 2005 through 2008. Our total amortization expense per Mcfe for the United States was $1.84, $1.40, and $1.05 in 2004, 2003, and 2002 and $2.02 for Brazil in 2004. We had no production in Brazil during 2003 and 2002. Included in our worldwide depreciation, depletion, and amortization expense is accretion expense of $0.08/Mcfe and $0.06/Mcfe for 2004 and 2003 attributable to SFAS No. 143 which we adopted in January 2003.

      Net quantities of proved developed and undeveloped reserves of natural gas and NGL, oil, and condensate, and changes in these reserves at December 31, 2004 are presented below. Information in these tables is based on our internal reserve report. Ryder Scott Company, an independent petroleum engineering firm, prepared an estimate of our natural gas and oil reserves for 88 percent of our properties. The total estimate of proved reserves prepared by Ryder Scott was within four percent of our internally prepared estimates presented in these tables. This information is consistent with estimates of reserves filed with other federal agencies except for differences of less than five percent resulting from actual production, acquisitions, property sales, necessary reserve revisions and additions to reflect actual experience. Ryder Scott was retained by and reports to the Audit Committee of our Board of Directors. The properties reviewed by Ryder Scott represented 88 percent of our proved properties based on value. The tables below exclude our Power segment’s equity interest in Sengkang in Indonesia and Aguaytia in Peru. Combined proved reserves balances for these interests were 132,336 MMcf of natural gas and 2,195 MBbls of oil, condensate and NGL for total natural gas equivalents of 145,507 MMcfe, all net to our ownership interests.

			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 178.

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			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 178.

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			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.

     During 2004, we had approximately 174 Bcfe of negative reserve revisions in the United States that were largely performance-driven. Our reserve revisions were primarily concentrated onshore in our coal bed methane operations and offshore in the Gulf of Mexico:

      Onshore. The onshore region recorded 71 Bcfe of negative reserve revisions. All of the negative reserve revisions are related to performance results from producing wells or the recent drilling program coupled with the related impact on booked proven undeveloped locations. In certain areas of the Arkoma and Black Warrior Basins, wells drilled in late 2003 had positive initial results; however, subsequent drilling and additional production history resulted in 70 Bcfe of negative revisions. In the Holly Field of North Louisiana, 14 Bcfe of reserves were revised downward as a result of production performance. These negative revisions were offset by better-than-anticipated performance in the Rockies and other Arklatex fields, resulting in positive reserve revisions of 13 Bcfe.

      Texas Gulf Coast. The Texas Gulf Coast region recorded 26 Bcfe of negative reserve revisions. The negative revisions were comprised of approximately 7 Bcfe of performance revisions to proved producing wells, approximately 6 Bcfe due to mechanical failures in five wells, and approximately 13 Bcfe due to lower-than-expected results from the 2004 development drilling program.

      Offshore. The offshore region recorded 77 Bcfe of negative reserve revisions in the Gulf of Mexico. Approximately 10 Bcfe of the revisions is a result of mechanical failures, and approximately 25 Bcfe is due to

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producing well performance. The remaining 42 Bcfe resulted from the drilling of development wells and adjustments to proved undeveloped reserves as a result of production performance in offsetting locations.

      There are numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and projecting the timing of development expenditures, including many factors beyond our control. The reserve data represents only estimates. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretations and judgment. All estimates of proved reserves are determined according to the rules prescribed by the SEC. These rules indicate that the standard of “reasonable certainty” be applied to proved reserve estimates. This concept of reasonable certainty implies that as more technical data becomes available, a positive, or upward, revision is more likely than a negative, or downward, revision. Estimates are subject to revision based upon a number of factors, including reservoir performance, prices, economic conditions and government restrictions. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of that estimate. Reserve estimates are often different from the quantities of natural gas and oil that are ultimately recovered. The meaningfulness of reserve estimates is highly dependent on the accuracy of the assumptions on which they were based. In general, the volume of production from natural gas and oil properties we own declines as reserves are depleted. Except to the extent we conduct successful exploration and development activities or acquire additional properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. There have been no major discoveries or other events, favorable or adverse, that may be considered to have caused a significant change in the estimated proved reserves since December 31, 2004. However in January 2005, we announced two acquisitions in east Texas and south Texas for $211 million. In March 2005, we acquired the interest of one of the parties in our net profits interest drilling program for $62 million. These acquisitions added properties with approximately 139 Bcfe of existing proved reserves and 52 MMcfe/d of current production.

      In 2003, we entered into agreements to sell interests in a maximum of 124 wells to Lehman Brothers and a subsidiary of Nabors Industries. As these wells are developed, Lehman and Nabors will pay 70 percent of the drilling and development costs in exchange for 70 percent of the net profits of the wells sold. As each well is commenced, Lehman and Nabors receive an overriding royalty interest in the form of a net profits interest in the well, under which they are entitled to receive 70 percent of the aggregate net profits of all wells until they have recovered 117.5 percent of their aggregate investment. Upon this recovery, the net profits interest will convert to a 2 percent overriding royalty interest in the wells for the remainder of the well’s productive life. We do not guarantee a return or the recovery of Lehman and Nabor’s costs. All parties to the agreement have the right to cease participation in the agreement at any time, at which time Lehman or Nabors will continue to receive its net profits interest on wells previously started, but will relinquish its right to participate in any future wells. During 2004, we sold interests in 54 wells and total proved reserves of 20,729 MMcf of natural gas and 1,323 MBbl of oil and natural gas liquids. They have paid $110 million of drilling and development costs and were paid $152 million of the revenues net of $11 million of expenses associated with these wells for the year ended December 31, 2004. In March 2005, we acquired all of the interests held by the Lehman subsidiary for $62 million.

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      Results of operations from producing activities by fiscal year were as follows at December 31 (in millions):

				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. 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.

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     The standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves at December 31 is as follows (in millions):

	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.

     For the calculations in the preceding table, estimated future cash inflows from estimated future production of proved reserves were computed using year-end prices of $6.22 per MMbtu for natural gas and $43.45 per barrel of oil at December 31, 2004. Adjustments for transportation and other charges resulted in a net price of $5.99 per Mcf of gas, $42.11 per barrel of oil and $32.13 per barrel of NGL at December 31, 2004. We may receive amounts different than the standardized measure of discounted cash flow for a number of reasons, including price changes and the effects of our hedging activities.

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      We do not rely upon the standardized measure when making investment and operating decisions. These decisions are based on various factors including probable and proved reserves, different price and cost assumptions, actual economic conditions, capital availability, and corporate investment criteria.

      The following are the principal sources of change in the worldwide standardized measure of discounted future net cash flows (in millions):

	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

⁽¹⁾ This disclosure reflects changes in the standardized measure calculation excluding the effects of hedging activities.

⁽²⁾ Includes operations in the United States and Brazil.

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SCHEDULE II

EL PASO CORPORATION

VALUATION AND QUALIFYING ACCOUNTS

Years Ended December 31, 2004, 2003 and 2002

(In millions)

				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.

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ITEM  9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

      None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

      As of December 31, 2004, we carried out an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer (CEO) and our Chief Financial Officer (CFO), as to the effectiveness, design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including the CEO and CFO, as appropriate, to allow timely discussion regarding required financial disclosure.

      Based on the results of this evaluation, our CEO and CFO concluded that as a result of the material weaknesses discussed below, our disclosure controls and procedures were not effective as of December 31, 2004. Because of these material weaknesses, we performed additional procedures to ensure that our financial statements as of and for the year ended December 31, 2004, were fairly presented in all material respects in accordance with generally accepted accounting principles.

Management’s Report on Internal Control Over Financial Reporting

      Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

      Under the supervision and with the participation of management, including the CEO and CFO, we made an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004. In making this assessment, we used the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

      As of December 31, 2004, we did not maintain effective controls over (1) access to financial application programs and data in certain information technology environments, (2) account reconciliations and (3) identification, capture and communication of financial data used in accounting for non-routine transactions or activities. A specific description of these control deficiencies, which we concluded are material weaknesses that existed as of December 31, 2004, is discussed below. A material weakness is a control deficiency, or combination of control deficiencies, that results in a more than remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected.

      Access to Financial Application Programs and Data. At December 31, 2004, we did not maintain effective controls over access to financial application programs and data at each of our operating segments. Specifically, we identified internal control deficiencies with respect to inadequate design of and compliance with our security access procedures related to identifying and monitoring conflicting roles (i.e., segregation of duties) and a lack of independent monitoring of access to various systems by our information technology staff, as well as certain users that require unrestricted security 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

182

number of our financial statement accounts, including accounts receivable, property, plant and equipment, accounts payable, revenue, operating expenses, 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, management has determined that these control deficiencies constitute a material weakness.

      Account Reconciliations. At December 31, 2004, we 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 liabilities, and taxes other than income taxes. Specifically, we found various instances in our 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. We also found instances within the company 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 to 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, management has determined that these control deficiencies constitute a material weakness.

      Identification, Capture and Communication of Financial Data Used in Accounting for Non-Routine Transactions or Activities. At December 31, 2004, we did not maintain effective controls related to identification, capture and communication of financial data used for accounting for non-routine transactions or activities. We identified control deficiencies 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 amounts, and accounting for divestiture of assets. These control deficiencies resulted in the restatement of our 2002 financial statements, as reflected in this annual report on Form 10-K, as well as adjustments impacting the fourth quarter of our 2004 financial statements. These control deficiencies could result in a misstatement in 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, management has determined that these control deficiencies constitute a material weakness.

      Because of the material weaknesses described above, management has concluded that, as of December 31, 2004, we did not maintain effective internal control over financial reporting, based on the criteria established in Internal Control — Integrated Framework issued by the COSO. Management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

Changes in Internal Control over Financial Reporting

      Changes Implemented Through December 31, 2004. During the course of 2004, management, with the oversight of our Audit Committee, devoted considerable effort to remediating deficiencies and to making improvements in our internal control over financial reporting. These improvements include the following enhancements in our internal controls over financial reporting:

•  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

183

•  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.

      Changes in 2005. Since December 31, 2004, we have taken action to correct the control deficiencies that resulted in the material weaknesses described in our report above including implementing monitoring controls in our information technology areas over users who require unrestricted access to perform their job responsibilities and formalizing and issuing a company-wide account reconciliation policy and providing training on the appropriate application of such policy. Other remedial actions have also been identified and are in the process of being implemented.

ITEM 9B. OTHER INFORMATION

      None.

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PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

      The information included under the captions, “Proposal No. 1 — Election of Directors” and “Section 16(a) Beneficial Ownership Reporting Compliance” in our Proxy Statement for the 2005 Annual Meeting of Stockholders is incorporated herein by reference. Information regarding our executive officers is presented in Part I, Item 1, Business, of this Form 10-K under the caption “Executive Officers of the Registrant.”

      As a result of the promulgation of Rule 10b5-1, we allow certain officers and directors to establish pre-established trading plans. Rule 10b5-1 allows certain officers and directors to establish written programs that permit an independent person who is not aware of inside information at the time of the trade to execute pre-established trades of our securities for the officer or director according to fixed parameters. As of March 10, 2005, no officer or director has a current trading plan. However, we intend to disclose the existence of any trading plan in compliance with Rule 10b5-1 in future filings with the SEC.

ITEM 11. EXECUTIVE COMPENSATION

      Information appearing under the caption “Executive Compensation” in our proxy statement for the 2005 Annual Meeting of Stockholders is incorporated herein by reference.

ITEM  12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

      Information appearing under the caption “Security Ownership of Certain Beneficial Owners and Management” in our proxy statement for the 2005 Annual Meeting of Stockholders is incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

      Information appearing under the caption “Certain Relationships and Related Transactions” in our proxy statement for the 2005 Annual Meeting of Stockholders is incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

      Information appearing under the caption “Principal Accountant Fees and Services” in our proxy statement for the 2005 Annual Meeting of Stockholders is incorporated herein by reference.

185

PART IV

ITEM  15.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

      (a) The following documents are filed as a part of this report:

      1. Financial statements.

      The following consolidated financial statements are included in Part II, Item 8 of this report:

		Page
	Consolidated Statements of Income		90
	Consolidated Balance Sheets		91
	Consolidated Statements of Cash Flows		93
	Consolidated Statements of Stockholders’ Equity		95
	Consolidated Statements of Comprehensive Income		96
	Notes to Consolidated Financial Statements		97
	Report of Independent Registered Public Accounting Firm		168
2. Financial statement schedules and supplementary information required to be submitted.
	Schedule II — Valuation and Qualifying Accounts		181
Midland Cogeneration Venture Limited Partnership
	Report of Independent Registered Public Accounting Firm		187
	Consolidated Balance Sheets		189
	Consolidated Statements of Operations		190
	Consolidated Statements of Partners’ Equity		191
	Consolidated Statements of Cash Flows		192
	Notes to Consolidated Financial Statements		193
3. Exhibit list			209

186

PRICEWATERHOUSECOOPERS LLP

Report of Independent Registered Public Accounting Firm

To the Partners and the Management Committee of

Midland Cogeneration Venture Limited Partnership:

      We have completed an integrated audit of Midland Cogeneration Venture Limited Partnership 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004 and audits of its December 31, 2003 and December 31, 2002 financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements

      In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, partners’ equity and cash flows present fairly, in all material respects, the financial position of the Midland Cogeneration Limited Partnership (a Michigan limited partnership) and its subsidiaries (MCV) at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the MCV’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      As explained in Note 2 to the financial statements, effective April 1, 2002, Midland Cogeneration Venture Limited Partnership changed its method of accounting for derivative and hedging activities in accordance with Derivative Implementation Group (“DIG”) Issue C-16.

Internal control over financial reporting

      Also, in our opinion, management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting appearing under Item 9(a), that the MCV maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the MCV maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The MCV’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the MCV’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

187

      A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

      Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Detroit, Michigan

February 25, 2005

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MIDLAND COGENERATION VENTURE LIMITED PARTNERSHIP

CONSOLIDATED BALANCE SHEETS AS OF DECEMBER 31,

(In Thousands)

			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

The accompanying notes are an integral part of these statements.

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MIDLAND COGENERATION VENTURE LIMITED PARTNERSHIP

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31,

(In Thousands)

			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

The accompanying notes are an integral part of these statements.

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MIDLAND COGENERATION VENTURE LIMITED PARTNERSHIP

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

FOR THE YEARS ENDED DECEMBER 31,

(In Thousands)

			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

The accompanying notes are an integral part of these statements.

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MIDLAND COGENERATION VENTURE LIMITED PARTNERSHIP

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31,

(In Thousands)

			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

The accompanying notes are an integral part of these statements.

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MIDLAND COGENERATION VENTURE LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)  The Partnership and Associated Risks

      MCV was organized to construct, own and operate a combined-cycle, gas-fired cogeneration facility (the “Facility”) located in Midland, Michigan. MCV was formed on January 27, 1987, and the Facility began commercial operation in 1990.

      In 1992, MCV had acquired the outstanding common stock of PVCO Corp., a previously inactive company. MCV and PVCO Corp. then entered into a partnership agreement to form MCV Gas Acquisition General Partnership (“MCV GAGP”) for the purpose of buying and selling natural gas on the spot market and other transactions involving natural gas activities. PVCO Corp. and MCV GAGP were dissolved on January 30, 2004 and July 2, 2004, respectively, due to inactivity.

      The Facility has a net electrical generating capacity of approximately 1500 MW and approximately 1.5 million pounds of process steam capacity per hour. MCV has entered into three principal energy sales agreements. MCV has contracted to (i) supply up to 1240 MW of electric capacity (“Contract Capacity”) to Consumers Energy Company (“Consumers”) under the Power Purchase Agreement (“PPA”), for resale to its customers through 2025, (ii) supply electricity and steam to The Dow Chemical Company (“Dow”) through 2008 and 2015, respectively, under the Steam and Electric Power Agreement (“SEPA”) and (iii) supply steam to Dow Corning Corporation (“DCC”) under the Steam Purchase Agreement (“SPA”) through 2011. From time to time, MCV enters into other sales agreements for the sale of excess capacity and/or energy available above MCV’s internal use and obligations under the PPA, SEPA and SPA. Results of operations are primarily dependent on successfully operating the Facility at or near contractual capacity levels and on Consumers’ ability to perform its obligations under the PPA. Sales pursuant to the PPA have historically accounted for over 90% of MCV’s revenues.

      The PPA permits Consumers, under certain conditions, to reduce the capacity and energy charges payable to MCV and/or to receive refunds of capacity and energy charges paid to MCV if the Michigan Public Service Commission (“MPSC”) does not permit Consumers to recover from its customers the capacity and energy charges specified in the PPA (the “regulatory-out” provision). Until September 15, 2007, however, the capacity charge may not be reduced below an average capacity rate of 3.77 cents per kilowatt-hour for the available Contract Capacity notwithstanding the “regulatory-out” provision. Consumers and MCV are required to support and defend the terms of the PPA.

      The Facility is a qualifying cogeneration facility (“QF”) originally certified by the Federal Energy Regulatory Commission (“FERC”) under the Public Utility Regulatory Policies Act of 1978, as amended (“PURPA”). In order to maintain QF status, certain operating and efficiency standards must be maintained on a calendar-year basis and certain ownership limitations must be met. In the case of a topping-cycle generating plant such as the Facility, the applicable operating standard requires that the portion of total energy output that is put to some useful purpose other than facilitating the production of power (the “Thermal Percentage”) be at least 5%. In addition, the Facility must achieve a PURPA efficiency standard (the sum of the useful power output plus one-half of the useful thermal energy output, divided by the energy input (the “Efficiency Percentage”)) of at least 45%. If the Facility maintains a Thermal Percentage of 15% or higher, the required Efficiency Percentage is reduced to 42.5%. Since 1990, the Facility has achieved the applicable Thermal and Efficiency Percentages. For the twelve months ended December 31, 2004, the Facility achieved a Thermal Percentage of 15.6% and an Efficiency Percentage of 47.6%. The loss of QF status could, among other things, cause MCV to lose its rights under PURPA to sell power from the Facility to Consumers at Consumers’ “avoided cost” and subject MCV to additional federal and state regulatory requirements.

      The Facility is wholly dependent upon natural gas for its fuel supply and a substantial portion of the Facility’s operating expenses consist of the costs of natural gas. MCV recognizes that its existing gas contracts are not sufficient to satisfy the anticipated gas needs over the term of the PPA and, as such, no assurance can be given as to the availability or price of natural gas after the expiration of the existing gas contracts. In

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MIDLAND COGENERATION VENTURE LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

addition, to the extent that the costs associated with production of electricity rise faster than the energy charge payments, MCV’s financial performance will be negatively affected. The extent of such impact will depend upon the amount of the average energy charge payable under the PPA, which is based upon costs incurred at Consumers’ coal-fired plants and upon the amount of energy scheduled by Consumers for delivery under the PPA. However, given the unpredictability of these factors, the overall economic impact upon MCV of changes in energy charges payable under the PPA and in future fuel costs under new or existing contracts cannot accurately be predicted.

      At both the state and federal level, efforts continue to restructure the electric industry. A significant issue to MCV is the potential for future regulatory denial of recovery by Consumers from its customers of above market PPA costs Consumers pays MCV. At the state level, the MPSC entered a series of orders from June 1997 through February 1998 (collectively the “Restructuring Orders”), mandating that utilities “wheel” third-party power to the utilities’ customers, thus permitting customers to choose their power provider. MCV, as well as others, filed an appeal in the Michigan Court of Appeals to protect against denial of recovery by Consumers of PPA charges. The Michigan Court of Appeals found that the Restructuring Orders do not unequivocally disallow such recovery by Consumers and, therefore, MCV’s issues were not ripe for appellate review and no actual controversy regarding recovery of costs could occur until 2008, at the earliest. In June 2000, the State of Michigan enacted legislation which, among other things, states that the Restructuring Orders (being voluntarily implemented by Consumers) are in compliance with the legislation and enforceable by the MPSC. The legislation provides that the rights of parties to existing contracts between utilities (like Consumers) and QFs (like MCV), including the rights to have the PPA charges recovered from customers of the utilities, are not abrogated or diminished, and permits utilities to securitize certain stranded costs, including PPA charges.

      In 1999, the U.S. District Court granted summary judgment to MCV declaring that the Restructuring Orders are preempted by federal law to the extent they prohibit Consumers from recovering from its customers any charge for avoided costs (or “stranded costs”) to be paid to MCV under PURPA pursuant to the PPA. In 2001, the United States Court of Appeals (“Appellate Court”) vacated the U.S. District Court’s 1999 summary judgment and ordered the case dismissed based upon a finding that no actual case or controversy existed for adjudication between the parties. The Appellate Court determined that the parties’ dispute is hypothetical at this time and the QFs’ (including MCV) claims are premised on speculation about how an order might be interpreted by the MPSC, in the future.

      Two significant issues that could affect MCV’s future financial performance are the price of natural gas and Consumers’ ability/obligation to pay PPA charges. Natural gas prices have historically been volatile and presently there is no consensus among forecasters on the price or range of future prices of natural gas. Even with the approved Resource Conservation Agreement and Reduced Dispatch Agreement, if gas prices continue at present levels or increase, the economics of operating the Facility may be adversely affected. Consumers’ ability/obligation to pay PPA charges may be affected by an MPSC order denying Consumers recovery from ratepayers. This issue is likely to be addressed in the timeframe of 2007 or beyond. MCV continues to monitor and participate in these matters as appropriate, and to evaluate potential impacts on both cash flows and recoverability of the carrying value of property, plant and equipment. MCV management cannot, at this time, predict the impact or outcome of these matters.

(2)  Significant Accounting Policies

      The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Following is a discussion of MCV’s significant accounting policies.

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MIDLAND COGENERATION VENTURE LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Principles of Consolidation

      The consolidated financial statements included the accounts of MCV and its wholly-owned subsidiaries, PVCO Corp. and MCV GAGP. Previously, all material transactions and balances among entities, which comprise MCV, had been eliminated in the consolidated financial statements. The 2004 dissolution of these wholly-owned subsidiaries had no impact on the financial position and results of operations.

Revenue Recognition

      MCV recognizes revenue for the sale of variable energy and fixed energy when delivered. Capacity and other installment revenues are recognized based on plant availability or other contractual arrangements.

Fuel Costs

      MCV’s fuel costs are those costs associated with securing natural gas, transportation and storage services necessary to generate electricity and steam from the Facility. These costs are recognized in the income statement based upon actual volumes burned to produce the delivered energy. In addition, MCV engages in certain cost mitigation activities to offset the fixed charges MCV incurs for these activities. The gains or losses resulting from these activities have resulted in net gains of approximately $6.7 million, $7.7 million and $3.9 million for the years ended 2004, 2003 and 2002, respectively. These net gains are reflected as a component of fuel costs.

      In July 2000, in response to rapidly escalating natural gas prices and since Consumers’ electric rates were frozen, MCV entered into a series of transactions with Consumers whereby Consumers agreed to reduce MCV’s dispatch level and MCV agreed to share with Consumers the savings realized by not having to generate electricity (“Dispatch Mitigation”). On January 1, 2004, Dispatch Mitigation ceased and Consumers began dispatching MCV pursuant to a 915 MW settlement and a 325 MW settlement “availability caps” provision (i.e., minimum dispatch of 1100 MW on- and off-peak (“Forced Dispatch”)). In 2004, MCV and Consumers entered into a Resource Conservation Agreement (“RCA”) and a Reduced Dispatch Agreement (“RDA”) which, among other things, provides that Consumers will economically dispatch MCV, if certain conditions are met. Such dispatch is expected to reduce electric production from what is occurring under the Forced Dispatch, as well as decrease gas consumption by MCV. The RCA provides that Consumers has a right of first refusal to purchase, at market prices, the gas conserved under the RCA. The RCA and RDA provide for the sharing of savings realized by not having to generate electricity. The RCA and RDA were approved by an order of the MPSC on January 25, 2005 and MCV and Consumers accepted the terms of the MPSC order making the RCA and RDA effective as of January 27, 2005. This MPSC order is subject to appeal by other parties. MCV management cannot predict the final outcome of any such appeal. While awaiting approval of this order, effective October 23, 2004, MCV and Consumers entered into an interim Dispatch Mitigation program for energy dispatch above 1100 MW up to 1240 MW of Contract Capacity under the PPA. This interim program, which was structured very similarly to the RCA and RDA, was terminated on January 27, 2005 with the effective date of the RCA/ RDA. For the twelve months ended December 31, 2004, 2003 and 2002, MCV estimates that these programs have resulted in net savings of approximately $1.6 million, $13.0 million and $2.5 million, a portion of which is realized in reduced maintenance expenditures in future years.

Accounts Receivable

      Accounts receivable and accounts receivable-related parties are recorded at the billed amount and do not bear interest. MCV evaluates the need for an allowance for doubtful accounts using MCV’s best estimate of the amount of probable credit losses. At December 31, 2004 and 2003, no allowance was provided since typically all receivables are collected within 30 days of each month end.

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MIDLAND COGENERATION VENTURE LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Inventory

      MCV’s inventory of natural gas is stated at the lower of cost or market, and valued using the last-in, first-out (“LIFO”) method. Inventory includes the costs of purchased gas, variable transportation and storage. The amount of reserve to reduce inventories from first-in, first-out (“FIFO”) basis to the LIFO basis at December 31, 2004 and 2003, was $10.3 million and $8.4 million, respectively. Inventory cost, determined on a FIFO basis, approximates current replacement cost.

Materials and Supplies

      Materials and supplies are stated at the lower of cost or market using the weighted average cost method. The majority of MCV’s materials and supplies are considered replacement parts for MCV’s Facility.

Depreciation

      Original plant, equipment and pipeline were valued at cost for the constructed assets and at the asset transfer price for purchased and contributed assets, and are depreciated using the straight-line method over an estimated useful life of 35 years, which is the term of the PPA, except for the hot gas path components of the GTGs which are primarily being depreciated over a 25-year life. Plant construction and additions, since commercial operations in 1990, are depreciated using the straight-line method over the remaining life of the plant which currently is 22 years. Major renewals and replacements, which extend the useful life of plant and equipment are capitalized, while maintenance and repairs are expensed when incurred. Major equipment overhauls are capitalized and amortized to the next equipment overhaul. Personal property is depreciated using the straight-line method over an estimated useful life of 5 to 15 years. The cost of assets and related accumulated depreciation are removed from the accounts when sold or retired, and any resulting gain or loss reflected in operating income.

Federal Income Tax

      MCV is not subject to Federal or State income taxes. Partnership earnings are taxed directly to each individual partner.

Statement of Cash Flows

      All liquid investments purchased with a maturity of three months or less at time of purchase are considered to be current cash equivalents.

Fair Value of Financial Instruments

      The carrying amounts of cash and cash equivalents and short-term investments approximate fair value because of the short maturity of these instruments. MCV’s short-term investments, which are made up of investment securities held-to-maturity, as of December 31, 2004 and December 31, 2003 have original maturity dates of approximately one year or less. The unique nature of the negotiated financing obligation discussed in Note 6 makes it unnecessary to estimate the fair value of the Owner Participants’ underlying debt and equity instruments supporting such financing obligation, since SFAS No. 107 “Disclosures about Fair Value of Financial Instruments” does not require fair value accounting for the lease obligation.

Accounting for Derivative Instruments and Hedging Activities

      Effective January 1, 2001, MCV adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” which was issued in June 1998 and then amended by SFAS No. 137, “Accounting for Derivative Instruments and Hedging Activities — Deferral of the Effective Date of SFAS No. 133,” SFAS No. 138 “Accounting for Certain Derivative Instruments and Certain Hedging Activities — An

196

MIDLAND COGENERATION VENTURE LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

amendment of FASB Statement No. 133” and SFAS No. 149 “Amendment of Statement 133 on Derivative Instruments and Hedging Activity (collectively referred to as “SFAS No. 133”). SFAS No. 133 establishes accounting and reporting standards requiring that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in a derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges in some cases allows a derivative’s gains and losses to offset related results on the hedged item in the income statement or permits recognition of the hedge results in other comprehensive income, and requires that a company formally document, designate and assess the effectiveness of transactions that receive hedge accounting.

Electric Sales Agreements

      MCV believes that its electric sales agreements currently do not qualify as derivatives under SFAS No. 133, due to the lack of an active energy market (as defined by SFAS No. 133) in the State of Michigan and the transportation cost to deliver the power under the contracts to the closest active energy market at the Cinergy hub in Ohio and as such does not record the fair value of these contracts on its balance sheet. If an active energy market emerges, MCV intends to apply the normal purchase, normal sales exception under SFAS No. 133 to its electric sales agreements, to the extent such exception is applicable.

Natural Gas Supply Contracts

      MCV management believes that its long-term natural gas contracts, which do not contain volume optionality, qualify under SFAS No. 133 for the normal purchases and normal sales exception. Therefore, these contracts are currently not recognized at fair value on the balance sheet.

      The FASB issued DIG Issue C-16, which became effective April 1, 2002, regarding natural gas commodity contracts that combine an option component and a forward component. This guidance requires either that the entire contract be accounted for as a derivative or the components of the contract be separated into two discrete contracts. Under the first alternative, the entire contract considered together would not qualify for the normal purchases and sales exception under the revised guidance. Under the second alternative, the newly established forward contract could qualify for the normal purchases and sales exception, while the option contract would be treated as a derivative under SFAS No. 133 with changes in fair value recorded through earnings. At April 1, 2002, MCV had nine long-term gas contracts that contained both an option and forward component. As such, they were no longer accounted for under the normal purchases and sales exception and MCV began mark-to-market accounting of these nine contracts through earnings. As of January 31, 2005, only four contracts of the original nine contracts, which contained an option and forward component remain in effect. In addition, as a result of implementing the RCA/ RDA, effective January 27, 2005, MCV has determined that as of the effective date of the RCA/ RDA, an additional nine long term contracts (for a total of 13) will no longer be accounted for under the normal purchases and sales exception, per SFAS No. 133 and will result in additional mark-to-market activity in 2005 and beyond. MCV expects future earnings volatility on both the remaining long term gas contracts that contain volume optionality as well as the long term gas contracts under the RCA/ RDA that will require mark-to-market recognition on a quarterly basis.

      Based on the natural gas prices, at the beginning of April 2002, MCV recorded a $58.1 million gain for the cumulative effect of this accounting change. From April 2002 to December 2004, MCV recorded an additional net mark-to-market loss of $2.3 million for these gas contracts. The cumulative mark-to-market gain through December 31, 2004 of $55.8 million is recorded as a current and non-current derivative asset on the balance sheet, as detailed below. These assets will reverse over the remaining life of these gas contracts, ranging from 2005 to 2007. For the twelve months ended December 31, 2004 and 2003, MCV recorded in “Fuel costs” losses of $19.2 million and $5.0 million, respectively, for net mark-to-market adjustments

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associated with these contracts. In addition, as of December 31, 2004 and 2003, MCV recorded “Derivative assets” in Current Assets in the amount of $31.4 million and $56.9 million, respectively, and for the same periods recorded “Derivative assets non-current” in Other Assets in the amount of $24.3 million and $18.1 million, respectively, representing the mark-to-market value on these long-term natural gas contracts.

Natural Gas Supply Futures and Options

      To manage market risks associated with the volatility of natural gas prices, MCV maintains a gas hedging program. MCV enters into natural gas futures contracts, option contracts, and over the counter swap transactions (“OTC swaps”) in order to hedge against unfavorable changes in the market price of natural gas in future months when gas is expected to be needed. These financial instruments are being utilized principally to secure anticipated natural gas requirements necessary for projected electric and steam sales, and to lock in sales prices of natural gas previously obtained in order to optimize MCV’s existing gas supply, storage and transportation arrangements.

      These financial instruments are derivatives under SFAS No. 133 and the contracts that are utilized to secure the anticipated natural gas requirements necessary for projected electric and steam sales qualify as cash flow hedges under SFAS No. 133, since they hedge the price risk associated with the cost of natural gas. MCV also engages in cost mitigation activities to offset the fixed charges MCV incurs in operating the Facility. These cost mitigation activities include the use of futures and options contracts to purchase and/or sell natural gas to maximize the use of the transportation and storage contracts when it is determined that they will not be needed for Facility operation. Although these cost mitigation activities do serve to offset the fixed monthly charges, these cost mitigation activities are not considered a normal course of business for MCV and do not qualify as hedges under SFAS No. 133. Therefore, the resulting mark-to-market gains and losses from cost mitigation activities are flowed through MCV’s earnings.

      Cash is deposited with the broker in a margin account at the time futures or options contracts are initiated. The change in market value of these contracts requires adjustment of the margin account balances. The margin account balance as of December 31, 2004 and 2003 was recorded as a current asset in “Broker margin accounts and prepaid expenses,” in the amount of $1.4 million and $4.1 million, respectively.

      For the twelve months ended December 31, 2004, MCV has recognized in other comprehensive income, an unrealized $34.5 million increase on the futures contracts and OTC swaps, which are hedges of forecasted purchases for plant use of market priced gas. This resulted in a net $65.8 million gain in other comprehensive income as of December 31, 2004. This balance represents natural gas futures, options and OTC swaps with maturities ranging from January 2005 to December 2009, of which $33.4 million of this gain is expected to be reclassified into earnings within the next twelve months. MCV also has recorded, as of December 31, 2004, a $63.6 million current derivative asset in “Derivative assets,” representing the mark-to-market gain on natural gas futures for anticipated projected electric and steam sales accounted for as hedges. In addition, for the twelve months ended December 31, 2004, MCV has recorded a net $36.5 million gain in earnings from hedging activities related to MCV natural gas requirements for Facility operations and a net $1.8 million gain in earnings from cost mitigation activities.

      For the twelve months ended December 31, 2003, MCV recognized an unrealized $5.0 million increase in other comprehensive income on the futures contracts, which are hedges of forecasted purchases for plant use of market priced gas, which resulted in a $31.3 million gain balance in other comprehensive income as of December 31, 2003. As of December 31, 2003, MCV had recorded a $29.9 million current derivative asset in “Derivative assets.” For the twelve months ended December 31, 2003, MCV had recorded a net $35.0 million gain in earnings from hedging activities related to MCV natural gas requirements for Facility operations and a net $1.0 million gain in earnings from cost mitigation activities.

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New Accounting Standard

      In 2003, the Emerging Issues Task Force (“EITF”) issued EITF 03-1 “The Meaning of Other-Than-Temporary Impairment and It’s Application to Certain Investments”. EITF 03-1 addresses how to determine the meaning of other-than-temporary impairment of certain debt and equity securities, the measurement of an impairment loss and accounting and disclosure considerations subsequent to the recognition of an other-than-temporary impairment. The various sections of EITF 03-1 became effective at various times during 2004. MCV has adopted this guidance and does not expect the application to materially affect it financial position or results of operations, since MCV’s investments approximate fair value due to the short maturity of its permitted investments.

(3)  Restricted Investment Securities Held-to-Maturity

      Non-current restricted investment securities held-to-maturity have carrying amounts that approximate fair value because of the short maturity of these instruments and consist of the following at December 31 (in thousands):

	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

      Accounts payable and accrued liabilities consist of the following at December 31 (in thousands):

		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

      Pursuant to individual gas contract terms with counterparties, deposit amounts or letters of credit may be required by one party to the other based upon the net amount of exposure. The net amount of exposure will vary with changes in market prices, credit provisions and various other factors. Collateral paid or received will be posted by one party to the other based on the net amount of the exposure. Interest is earned on funds on deposit. As of December 31, 2004, MCV is supplying credit support to two gas suppliers; one in the form of a letter of credit in the amount of $2.4 million; and cash on deposit with the other in the amount of $7.3 million. As of December 31, 2004, MCV is holding $19.6 million of cash on deposit from two of MCV’s brokers. In addition as of December 31, 2004, MCV is also holding letters of credit totaling $208.6 million from two gas suppliers, of which $184.0 million is a letter of credit from El Paso Corporation (“El Paso”), a related party.

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(6)  Long-Term Debt

      Long-term debt consists of the following at December 31 (in thousands):

	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

      In June 1990, MCV obtained permanent financing for the Facility by entering into sale and leaseback agreements (“Overall Lease Transaction”) with a lessor group, related to substantially all of MCV’s fixed assets. Proceeds of the financing were used to retire borrowings outstanding under existing loan commitments, make a capital distribution to the Partners and retire a portion of notes issued by MCV to MEC Development Corporation (“MDC”) in connection with the transfer of certain assets by MDC to MCV. In accordance with SFAS No. 98, “Accounting For Leases,” the sale and leaseback transaction has been accounted for as a financing arrangement.

      The financing obligation utilizes the effective interest rate method, which is based on the minimum lease payments required through the end of the basic lease term of 2015 and management’s estimate of additional anticipated obligations after the end of the basic lease term. The effective interest rate during the remainder of the basic lease term is approximately 9.4%.

      Under the terms of the Overall Lease Transaction, MCV sold undivided interests in all of the fixed assets of the Facility for approximately $2.3 billion, to five separate owner trusts (“Owner Trusts”) established for the benefit of certain institutional investors (“Owner Participants”). U.S. Bank National Association (formerly known as State Street Bank and Trust Company) serves as owner trustee (“Owner Trustee”) under each of the Owner Trusts, and leases undivided interests in the Facility on behalf of the Owner Trusts to MCV for an initial term of 25 years. CMS Midland Holdings Company (“CMS Holdings”), currently a wholly owned subsidiary of Consumers, acquired a 35% indirect equity interest in the Facility through its purchase of an interest in one of the Owner Trusts.

      The Overall Lease Transaction requires MCV to achieve certain rent coverage ratios and other financial tests prior to a distribution to the Partners. Generally, these financial tests become more restrictive with the passage of time. Further, MCV is restricted to making permitted investments and incurring permitted indebtedness as specified in the Overall Lease Transaction. The Overall Lease Transaction also requires filing of certain periodic operating and financial reports, notification to the lessors of events constituting a material adverse change, significant litigation or governmental investigation, and change in status as a qualifying facility under FERC proceedings or court decisions, among others. Notification and approval is required for plant modification, new business activities, and other significant changes, as defined. In addition, MCV has agreed to indemnify various parties to the sale and leaseback transaction against any expenses or environmental claims asserted, or certain federal and state taxes imposed on the Facility, as defined in the Overall Lease Transaction.

      Under the terms of the Overall Lease Transaction and refinancing of the tax-exempt bonds, approximately $25.0 million of transaction costs were a liability of MCV and have been recorded as a deferred cost. Financing costs incurred with the issuance of debt are deferred and amortized using the interest method over the remaining portion of the 25-year lease term. Deferred financing costs of approximately $1.2 million, $1.4 million and $1.5 million were amortized in the years 2004, 2003 and 2002, respectively.

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      Interest and fees incurred related to long-term debt arrangements during 2004, 2003 and 2002 were $103.4 million, $111.9 million and $118.3 million, respectively.

      Interest and fees paid during 2004, 2003 and 2002 were $108.6 million, $115.4 million and $122.1 million, respectively.

      Minimum payments due under these long-term debt arrangements over the next five years are (in thousands):

	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

     Revolving Credit Agreement

      MCV has also entered into a working capital line (“Working Capital Facility”), which expires August 27, 2005. Under the terms of the existing agreement, MCV can borrow up to the $50.0 million commitment, in the form of short-term borrowings or letters of credit collateralized by MCV’s natural gas inventory and earned receivables. At any given time, borrowings and letters of credit are limited by the amount of the borrowing base, defined as 90% of earned receivables and 50% of natural gas inventory, capped at $15 million. MCV did not utilize the Working Capital Facility during the year 2004, except for letters of credit associated with normal business practices. At December 31, 2004, MCV had $47.6 million available under its Working Capital Facility. As of December 31, 2004, MCV’s borrowing base was capped at the maximum amount available of $50.0 million and MCV had outstanding letters of credit in the amount of $2.4 million. MCV believes that amounts available to it under the Working Capital Facility along with available cash reserves will be sufficient to meet any working capital shortfalls that might occur in the near term.

     Intercreditor Agreement

      MCV has also entered into an Intercreditor Agreement with the Owner Trustee, Working Capital Lender, U.S. Bank National Association as Collateral Agent (“Collateral Agent”) and the Senior and Subordinated Indenture Trustees. Under the terms of this agreement, MCV is required to deposit all revenues derived from the operation of the Facility with the Collateral Agent for purposes of paying operating expenses and rent. In addition, these funds are required to pay construction modification costs and to secure future rent payments. As of December 31, 2004, MCV has deposited $138.2 million into the reserve account. The reserve account is to be maintained at not less than $40 million nor more than $137 million (or debt portion of next succeeding basic rent payment, whichever is greater). Excess funds in the reserve account are periodically transferred to MCV. This agreement also contains provisions governing the distribution of revenues and rents due under the Overall Lease Transaction, and establishes the priority of payment among the Owner Trusts, creditors of the Owner Trusts, creditors of MCV and the Partnership.

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(7)  Commitments and Other Agreements

      MCV has entered into numerous commitments and other agreements related to the Facility. Principal agreements are summarized as follows:

     Power Purchase Agreement

      MCV and Consumers have executed the PPA for the sale to Consumers of a minimum amount of electricity, subject to the capacity requirements of Dow and any other permissible electricity purchasers. Consumers has the right to terminate and/or withhold payment under the PPA if the Facility fails to achieve certain operating levels or if MCV fails to provide adequate fuel assurances. In the event of early termination of the PPA, MCV would have a maximum liability of approximately $270 million if the PPA were terminated in the 12th through 24th years. The term of this agreement is 35 years from the commercial operation date and year-to-year thereafter.

     Steam and Electric Power Agreement

      MCV and Dow executed the SEPA for the sale to Dow of certain minimum amounts of steam and electricity for Dow’s facilities.

      If the SEPA is terminated, and Consumers does not fulfill MCV’s commitments as provided in the Backup Steam and Electric Power Agreement, MCV will be required to pay Dow a termination fee, calculated at that time, ranging from a minimum of $60 million to a maximum of $85 million. This agreement provides for the sale to Dow of steam and electricity produced by the Facility for terms of 25 years and 15 years, respectively, commencing on the commercial operation date and year-to-year thereafter.

     Steam Purchase Agreement

      MCV and DCC executed the SPA for the sale to DCC of certain minimum amounts of steam for use at the DCC Midland site. Steam sales under the SPA commenced in July 1996. Termination of this agreement, prior to expiration, requires the terminating party to pay to the other party a percentage of future revenues, which would have been realized had the initial term of 15 years been fulfilled. The percentage of future revenues payable is 50% if termination occurs prior to the fifth anniversary of the commercial operation date and 33¹/3% if termination occurs after the fifth anniversary of this agreement. The term of this agreement is 15 years from the commercial operation date of steam deliveries under the contract and year-to-year thereafter.

     Gas Supply Agreements

      MCV has entered into gas purchase agreements with various producers for the supply of natural gas. The current contracted volume totals 238,531 MMBtu per day annual average for 2005. As of January 1, 2005, gas contracts with U.S. suppliers provide for the purchase of 173,336 MMBtu per day while gas contracts with Canadian suppliers provide for the purchase of 65,195 MMBtu per day. Some of these contracts require MCV to pay for a minimum amount of natural gas per year, whether or not taken. The estimated minimum commitments under these contracts based on current long term prices for gas for the years 2005 through 2009 are $384.6 million, $402.1 million, $436.7 million, $358.8 million and $324.0 million, respectively. A portion of these payments may be utilized in future years to offset the cost of quantities of natural gas taken above the minimum amounts.

     Gas Transportation Agreements

      MCV has entered into firm natural gas transportation agreements with various pipeline companies. These agreements require MCV to pay certain reservation charges in order to reserve the transportation capacity.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

MCV incurred reservation charges in 2004, 2003 and 2002, of $35.5 million, $34.8 million and $35.1 million, respectively. The estimated minimum reservation charges required under these agreements for each of the years 2005 through 2009 are $34.3 million, $30.0 million, $21.6 million, $21.6 million and $21.6 million, respectively. These projections are based on current commitments.

     Gas Turbine Service Agreements

      Under a Service Agreement, as amended, with Alstom, which commenced on January 1, 1990 and was set to expire upon the earlier of the completion of the sixth series of major GTG inspections or December 31, 2009, Alstom sold MCV an initial inventory of spare parts for the GTGs and provided qualified service personnel and supporting staff to assist MCV, to perform scheduled inspections on the GTGs, and to repair the GTGs at MCV’s request. The Service Agreement was terminated for cause by MCV in February 2004. Alstom disputed MCV’s right to terminate for cause. The parties settled the dispute and the agreement terminated in February 2004.MCV has a maintenance service and parts agreement with General Electric International, Inc. (“GEII”), which commenced July 1, 2004 (“GEII Agreement”). GEII will provide maintenance services and hot gas path parts for MCV’s twelve GTGs, including providing an initial inventory of spare parts for the GTGs and providing qualified service personnel and supporting staff to assist MCV, to perform scheduled inspections on the GTGs, and to repair the GTGs at MCV’s request. Under terms and conditions similar to the MCV/ Alstom Service Agreement, as described above the GEII Agreement will cover four rounds of major GTG inspections, which are expected to be completed by the year 2015, at a savings to MCV as compared to the Service Agreement with Alstom. MCV is to make monthly payments over the life of the contract totaling approximately $207 million (subject to escalations based on defined indices. The GEII Agreement can be terminated by either party for cause or convenience. Should termination for convenience occur, a buy out amount will be paid by the terminating party with payments ranging from approximately $19.0 million to $.9 million, based upon the number of operating hours utilized since commencement of the GEII Agreement.

     Steam Turbine Service Agreement

      MCV entered into a nine year Steam Turbine Maintenance Agreement with General Electric Company effective January 1, 1995, which is designed to improve unit reliability, increase availability and minimize unanticipated maintenance costs. In addition, this contract includes performance incentives and penalties, which are based on the length of each scheduled outage and the number of forced outages during a calendar year. Effective February 1, 2004, MCV and GE amended this contract to extend its term through August 31, 2007. MCV will continue making monthly payments over the life of the contract, which will total $22.3 million (subject to escalation based on defined indices). The parties have certain termination rights without incurring penalties or damages for such termination. Upon termination, MCV is only liable for payment of services rendered or parts provided prior to termination.

     Site Lease

      In December 1987, MCV leased the land on which the Facility is located from Consumers (“Site Lease”). MCV and Consumers amended and restated the Site Lease to reflect the creation of five separate undivided interests in the Site Lease as of June 1, 1990. Pursuant to the Overall Lease Transaction, MCV assigned these undivided interests in the Site Lease to the Owner Trustees, which in turn subleased the undivided interests back to MCV under five separate site subleases.

      The Site Lease is for a term which commenced on December 29, 1987, and ends on December 31, 2035, including two renewal options of five years each. The rental under the Site Lease is $.6 million per annum, including the two five-year renewal terms.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(8)  Contingencies

Property Taxes

      In 1997, MCV filed a property tax appeal against the City of Midland at the Michigan Tax Tribunal contesting MCV’s 1997 property taxes. Subsequently, MCV filed appeals contesting its property taxes for tax years 1998 through 2004 at the Michigan Tax Tribunal. A trial was held for tax years 1997-2000. The appeals for tax years 2001-2004 are being held in abeyance. On January 23, 2004, the Michigan Tax Tribunal issued its decision in MCV’s tax appeal against the City of Midland for tax years 1997 through 2000 and has issued several orders correcting errors in the initial decision (together the “MTT Decision”). MCV management has estimated that the MTT Decision will result in a refund to MCV for the tax years 1997 through 2000 of at least approximately $35.3 million in taxes plus $9.6 million of interest as of December 31, 2004. The MTT Decision has been appealed to the Michigan Appellate Court by the City of Midland. MCV has filed a cross-appeal at the Michigan Appellate Court. MCV management cannot predict the outcome of these legal proceedings. MCV has not recognized any of the above stated refunds (net of approximately $16.1 million of deferred expenses) in earnings at this time.

NOx Allowances

      The United States Environmental Protection Agency (“US EPA”) has approved the State of Michigan’s — State Implementation Plan (“SIP”), which includes an interstate NOx budget and allowance trading program administered by the US EPA beginning in 2004. Each NOx allowance permits a source to emit one ton of NOx during the seasonal control period, which for 2004 was from May 31 through September 30. NOx allowances may be bought or sold and unused allowances may be “banked” for future use, with certain limitations. MCV estimates that it will have excess NOx allowances to sell under this program. Consumers has given notice to MCV that it believes the ownership of the NOx allowances under this program belong, at least in part, to Consumers. MCV has initiated the dispute resolution process pursuant to the PPA to resolve this issue and the parties have entered into a standstill agreement deferring the resolution of this dispute. However, either party may terminate the standstill agreement at any time and reinstate the PPA’s dispute resolution provisions. MCV management cannot predict the outcome of this issue. As of December 31, 2004, MCV has sold 1,200 tons of 2004 allowances for $2.7 million, which is recorded in “Accounts payable and accrued liabilities”, pending resolution of ownership of these credits.

Environmental Issues

      On July 12, 2004 the Michigan Department of Environmental Quality (“DEQ”), Air Quality Division, issued MCV a “Letter of Violation” asserting that MCV violated its Air Use Permit to Install No. 209-02 (“PTI”) by exceeding the carbon monoxide emission limit on the Unit 14 GTG duct burner and failing to maintain certain records in the required format. On July 13, 2004 the DEQ, Water Division, issued MCV a “Notice Letter” asserting MCV violated its National Pollutant Discharge Elimination System Permit by discharging heated process waste water into the storm water system, failure to document inspections, and other minor infractions (“alleged NPDES violations”).

      MCV has declared all duct burners as unavailable for operational use (which reduces the generation capability of the Facility by approximately 100 MW) and is assessing the duct burner issue and has begun other corrective action to address the DEQ’s assertions. MCV disagrees with certain of the DEQ’s assertions. MCV filed responses to these DEQ letters in July and August 2004. On December 13, 2004, the DEQ informed MCV that it was pursuing an escalated enforcement action against MCV regarding the alleged violations of MCV’s PTI. The DEQ also stated that the alleged violations are deemed federally significant and, as such, placed MCV on the United States Environmental Protection Agency’s High Priority Violators List (“HPVL”). The DEQ and MCV are pursuing voluntary settlement of this matter, which will satisfy state and federal requirements and remove MCV from the HPVL. Any such settlement is likely to involve a fine,

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but the DEQ has not, at this time, stated what, if any, fine they will seek to impose. At this time, MCV management cannot predict the financial impact or outcome of these issues, however, MCV believes it has resolved all issues associated with the alleged NPDES violations and does not expect any further MDEQ actions on this NPDES matter.

(9)  Voluntary Severance Program

      In July 2004, MCV announced a Voluntary Severance Program (“VSP”) for all employees (union and non-union employees), subject to certain eligibility requirements. The VSP entitled participating employees, upon termination, to a lump sum payment, based upon number of years of service up to a maximum of 52 weeks of wages. Nineteen employees elected to participate in the VSP and MCV has recorded $1.7 million of severance costs in “Operating Expenses” related to the nineteen employees.

(10)  Retirement Benefits

Postretirement Health Care Plans

      In 1992, MCV established defined cost postretirement health care plans (“Plans”) that cover all full-time employees, excluding key management. The Plans provide health care credits, which can be utilized to purchase medical plan coverage and pay qualified health care expenses. Participants become eligible for the benefits if they retire on or after the attainment of age 65 or upon a qualified disability retirement, or if they have 10 or more years of service and retire at age 55 or older. The Plans granted retroactive benefits for all employees hired prior to January 1, 1992. This prior service cost has been amortized to expense over a five-year period. MCV annually funds the current year service and interest cost as well as amortization of prior service cost to both qualified and non-qualified trusts. The MCV accounts for retiree medical benefits in accordance with SFAS 106, “Employers Accounting for Postretirement Benefits Other Than Pensions.” This standard required the full accrual of such costs during the years that the employee renders service to the MCV until the date of full eligibility. The accumulated benefit obligation of the Plans were $4.9 million at December 31, 2004 and $3.3 million at December 31, 2003. The measurement date of these Plans was December 31, 2004.

      The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Act”) was signed into law in December 2003. The Act expanded Medicare to include, for the first time, coverage for prescription drugs. At December 31, 2003, based upon FASB staff position, SFAS No. 106-1, “Employers Accounting for Postretirement Benefits Other Than Pensions,” MCV had elected to defer financial recognition of this legislation until issuance of final accounting guidance. The final SFAS No. 106-2 was issued in second quarter 2004 and supersedes SFAS No. 106-1, which MCV adopted during this same period. The adoption of this standard had no impact to MCV’s financial position because MCV does not consider its Plans to be actuarially equivalent. The Plans benefits provided to eligible participants are not annual or on-going in nature, but are a readily exhaustible, lump-sum amount available for use at the discretion of the participant.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      The following table reconciles the change in the Plans’ benefit obligation and change in Plan assets as reflected on the balance sheet as of December 31 (in thousands):

	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	$	—		$	—

      Net periodic postretirement health care cost for years ending December 31, included the following components (in thousands):

	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

      Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects (in thousands):

	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

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      Assumptions used in accounting for the Post-Retirement Health Care Plan were as follows:

		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%

      The long-term rate of return on Plan assets is established based on MCV’s expectations of asset returns for the investment mix in its Plan (with some reliance on historical asset returns for the Plans). The expected returns for various asset categories are blended to derive one long-term assumption.

      Plan Assets. Citizens Bank has been appointed as trustee (“Trustee”) of the Plan. The Trustee serves as investment consultant, with the responsibility of providing financial information and general guidance to the MCV Benefits Committee. The Trustee shall invest the assets of the Plan in the separate investment options in accordance with instructions communicated to the Trustee from time to time by the MCV Benefit Committee. The MCV Benefits Committee has the fiduciary and investment selection responsibility for the Plan. The MCV Benefits Committee consists of MCV Officers (excluding the President and Chief Executive Officer).

      The MCV has a target allocation of 80% equities and 20% debt instruments. These investments emphasis total growth return, with a moderate risk level. The MCV Benefits Committee reviews the performance of the Plan investments quarterly, based on a long-term investment horizon and applicable benchmarks, with rebalancing of the investment portfolio, at the discretion of the MCV Benefits Committee.

      MCV’s Plan’s weighted-average asset allocations, by asset category are as follows as of December 31:

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

      Contributions. MCV expects to contribute approximately $.4 million to the Plan in 2005.

     Retirement and Savings Plans

      MCV sponsors a defined contribution retirement plan covering all employees. Under the terms of the plan, MCV makes contributions to the plan of either five or ten percent of an employee’s eligible annual compensation dependent upon the employee’s age. MCV also sponsors a 401(k) savings plan for employees. Contributions and costs for this plan are based on matching an employee’s savings up to a maximum level. In 2004, 2003 and 2002, MCV contributed $1.4 million, $1.3 million and $1.2 million, respectively under these plans.

     Supplemental Retirement Benefits

      MCV provides supplemental retirement, postretirement health care and excess benefit plans for key management. These plans are not qualified plans under the Internal Revenue Code; therefore, earnings of the trusts maintained by MCV to fund these plans are taxable to the Partners and trust assets are included in the assets of MCV.

(11) Partners’ Equity and Related Party Transactions

      The following table summarizes the nature and amount of each of MCV’s Partner’s equity interest, interest in profits and losses of MCV at December 31, 2004, and the nature and amount of related party

207

MIDLAND COGENERATION VENTURE LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

transactions or agreements that existed with the Partners or affiliates as of December 31, 2004, 2003 and 2002, and for each of the twelve month periods ended December 31 (in thousands).

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

Footnotes to Partners’ Equity and Related Party Transactions

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

208

EL PASO CORPORATION

EXHIBIT LIST

December 31, 2004

      Each exhibit identified below is filed as part of this report. Exhibits not incorporated by reference to a prior filing are designated by an “*”; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated. Exhibits designated with a “+” constitute a management contract or compensatory plan or arrangement required to be filed as an exhibit to this report pursuant to Item 14(c) of Form 10-K.

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
3	.A	Restated Certificate of Incorporation effective as of August 11, 2003 (Exhibit 3.A to our 2003 Second Quarter Form 10-Q)
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 JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee

209

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 8K filed April 18, 2003)

210

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
*+10	.G.1	Amendment No. 1 effective as of July 16, 1999 to the Stock Option Plan for Non-Employee Directors
+10	.G.2	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 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
*+10	.I.1	Amendment No. 1 effective as of December 3, 1998 to the 1995 Omnibus Compensation Plan
*+10	.I.2	Amendment No. 2 effective as of January 20, 1999 to the 1995 Omnibus Compensation Plan
+10	.J	1999 Omnibus Incentive Compensation Plan dated January 20, 1999 (Exhibit 10.1 to our Form S-8 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 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)
*+10	.L.1	Amendment No. 2 effective as of June 1, 2004 to the Supplemental Benefits Plan
*+10	.M	Senior Executive Survivor Benefit Plan Amended and Restated effective as of August 1, 1998
+10	.M.1	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)

211

*+10	.N	Key Executive Severance Protection Plan Amended and Restated effective as of August 1, 1998
+10	.N.1	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
+10	.P.1	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 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
*+10	.S	Executive Award Plan of Sonat Inc. Amended and Restated effective as of July 23, 1998, as amended May 27, 1999
+10	.S.1	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 10.1 to our Form S-8 filed December 18, 2000); Amendment No. 1 effective as of December 1, 2000 to the Omnibus Plan for Management Employees (Exhibit 10.1 to our Form S-8 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 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)

212

+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.1 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 10.0 to our 2000 Form 10-K)
+10	.X	Letter Agreement dated September 22, 2000 between El Paso and D. Dwight Scott (Exhibit 10.W to our 2002 Third Quarter Form 10-Q)
+10	.X.1	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)
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)

213

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)
*21		Subsidiaries of El Paso
*23	.A	Consent of Independent Registered Public Accounting Firm, PricewaterhouseCoopers LLP (Houston)
*23	.B	Consent of Independent Registered Public Accounting Firm, PricewaterhouseCoopers LLP (Detroit)
*23	.C	Consent of Ryder Scott Company, L.P.
*31	.A	Certification of Chief Executive Officer pursuant to sec. 302 of the Sarbanes-Oxley Act of 2002
*31	.B	Certification of Chief Financial Officer pursuant to sec. 302 of the Sarbanes-Oxley Act of 2002
*32	.A	Certification of Chief Executive Officer pursuant to 18 U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the Sarbanes-Oxley Act of 2002
*32	.B	Certification of Chief Financial Officer pursuant to 18 U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the Sarbanes-Oxley Act of 2002

Undertaking

      We hereby undertake, pursuant to Regulation S-K, Item 601(b), paragraph (4) (iii), to furnish to the Securities and Exchange Commission upon request all constituent instruments defining the rights of holders of our long-term debt and consolidated subsidiaries not filed herewith for the reason that the total amount of securities authorized under any of such instruments does not exceed 10 percent of our total consolidated assets.

214

SIGNATURES

      Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, El Paso Corporation has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the [  ]th day of March 2005.

EL PASO CORPORATION

Registrant

By  /s/ Douglas L. Foshee

Douglas L. Foshee

President and Chief Executive Officer

     Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of El Paso Corporation and in the capacities and on the dates indicated:

Signature	Title	Date
/s/ Douglas L. Foshee (Douglas L. Foshee)	President, Chief Executive Officer and Director (Principal Executive Officer)	March 25, 2005
/s/ D. Dwight Scott (D. Dwight Scott)	Executive Vice President and Chief Financial Officer (Principal Financial Officer)	March 25, 2005
/s/ Jeffrey I. Beason (Jeffrey I. Beason)	Senior Vice President and Controller (Principal Accounting Officer)	March 25, 2005
/s/ Ronald L. Kuehn, Jr. (Ronald L. Kuehn, Jr.)	Chairman of the Board and Director	March 25, 2005
/s/ John M. Bissell (John M. Bissell)	Director	March 25, 2005
/s/ Juan Carlos Braniff (Juan Carlos Braniff)	Director	March 25, 2005
/s/ James L. Dunlap (James L. Dunlap)	Director	March 25, 2005
/s/ Robert W. Goldman (Robert W. Goldman)	Director	March 25, 2005
/s/ Anthony W. Hall, Jr. (Anthony W. Hall, Jr.)	Director	March 25, 2005

215

Signature	Title	Date
/s/ Thomas R. Hix (Thomas R. Hix)	Director	March 25, 2005
/s/ William H. Joyce (William H. Joyce)	Director	March 25, 2005
/s/ J. Michael Talbert (J. Michael Talbert)	Director	March 25, 2005
/s/ John L. Whitmire (John L. Whitmire)	Director	March 25, 2005
/s/ Joe B. Wyatt (Joe B. Wyatt)	Director	March 25, 2005

216

EL PASO CORPORATION

EXHIBIT INDEX

December 31, 2004

      Each exhibit identified below is filed as part of this report. Exhibits not incorporated by reference to a prior filing are designated by an “*”; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated. Exhibits designated with a “+” constitute a management contract or compensatory plan or arrangement required to be filed as an exhibit to this report pursuant to Item 14(c) of Form 10-K.

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
3	.A	Restated Certificate of Incorporation effective as of August 11, 2003 (Exhibit 3.A to our 2003 Second Quarter Form 10-Q)
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 JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee

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 8K 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
*+10	.G.1	Amendment No. 1 effective as of July 16, 1999 to the Stock Option Plan for Non-Employee Directors
+10	.G.2	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 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
*+10	.I.1	Amendment No. 1 effective as of December 3, 1998 to the 1995 Omnibus Compensation Plan
*+10	.I.2	Amendment No. 2 effective as of January 20, 1999 to the 1995 Omnibus Compensation Plan
+10	.J	1999 Omnibus Incentive Compensation Plan dated January 20, 1999 (Exhibit 10.1 to our Form S-8 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 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)
*+10	.L.1	Amendment No. 2 effective as of June 1, 2004 to the Supplemental Benefits Plan
*+10	.M	Senior Executive Survivor Benefit Plan Amended and Restated effective as of August 1, 1998
+10	.M.1	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

+10	.N.1	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
+10	.P.1	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 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
*+10	.S	Executive Award Plan of Sonat Inc. Amended and Restated effective as of July 23, 1998, as amended May 27, 1999
+10	.S.1	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 10.1 to our Form S-8 filed December 18, 2000); Amendment No. 1 effective as of December 1, 2000 to the Omnibus Plan for Management Employees (Exhibit 10.1 to our Form S-8 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 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.1 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 10.0 to our 2000 Form 10-K)
+10	.X	Letter Agreement dated September 22, 2000 between El Paso and D. Dwight Scott (Exhibit 10.W to our 2002 Third Quarter Form 10-Q)
+10	.X.1	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)
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)

*21		Subsidiaries of El Paso
*23	.A	Consent of Independent Registered Public Accounting Firm, PricewaterhouseCoopers LLP (Houston)
*23	.B	Consent of Independent Registered Public Accounting Firm PricewaterhouseCoopers LLP (Detroit)
*23	.C	Consent of Ryder Scott Company, L.P.
*31	.A	Certification of Chief Executive Officer pursuant to sec. 302 of the Sarbanes-Oxley Act of 2002
*31	.B	Certification of Chief Financial Officer pursuant to sec. 302 of the Sarbanes-Oxley Act of 2002
*32	.A	Certification of Chief Executive Officer pursuant to 18 U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the Sarbanes-Oxley Act of 2002
*32	.B	Certification of Chief Financial Officer pursuant to 18 U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the Sarbanes-Oxley Act of 2002

EX-2.B.1

EXHIBIT 2.B.1

PURCHASE AND SALE AGREEMENT

By and Among

ENTERPRISE GP HOLDINGS L.P.

And

SABINE RIVER INVESTORS I, L.L.C.
SABINE RIVER INVESTORS II, L.L.C.
EL PASO CORPORATION
GULFTERRA GP HOLDING COMPANY

January 14, 2005

TABLE OF CONTENTS

ARTICLE I DEFINITIONS	1
Section 1.1 Definitions	1
Section 1.2 Rules of Construction	4
ARTICLE II PURCHASE AND SALE	5
Section 2.1 Closing	5
ARTICLE III REPRESENTATIONS AND WARRANTIES	6
Section 3.1 Representations and Warranties of El Paso and El Paso GP Holdco	6
Section 3.2 Representations and Warranties of El Paso and the Unitholders	8
Section 3.3 Representations and Warranties of Enterprise Concerning the Transaction	10
ARTICLE IV COVENANTS AND AGREEMENTS	12
Section 4.1 Commercially Reasonable Efforts; Further Assurances	12
Section 4.2 Intentionally Omitted	12
Section 4.3 Expenses	12
ARTICLE V REMEDIES FOR DEFAULT	12
Section 5.1 Indemnity Regarding Section 3.1 Representations and Covenants	12
Section 5.2 Indemnity Regarding Section 3.2 Representations and Covenants	12
Section 5.3 Indemnity Regarding Section 3.3 Representations and Covenants	13
Section 5.4 Survival of Representations	13
Section 5.5 Enforcement of this Agreement	13
Section 5.6 Exclusive Remedy	13
Section 5.7 General Limitation of Damages	13
Section 5.8 No Waiver Relating to Claims for Fraud/Willful Misconduct	13
ARTICLE VI MISCELLANEOUS	14
Section 6.1 Notices	14
Section 6.2 Governing Law; Jurisdiction; Waiver of Jury Trial	14
Section 6.3 Entire Agreement; Amendments and Waivers	15
Section 6.4 Binding Effect and Assignment	15
Section 6.5 Severability	15
Section 6.6 Execution	16

Schedule 1 Enterprise MLP Common Units

i

PURCHASE AND SALE AGREEMENT

     This PURCHASE AND SALE AGREEMENT (this “Agreement”), dated as of January 14, 2005 (the “Effective Date”), is entered into by and among (a) El Paso Corporation, a Delaware corporation (“El Paso”), Sabine River Investors I, L.L.C., a Delaware limited liability company (“El Paso Sub 1”), Sabine River Investors II, L.L.C., a Delaware limited liability company (“El Paso Sub 2”), and collectively with El Paso Sub 1, the “Unitholders”), and GulfTerra GP Holding Company, a Delaware corporation (“El Paso GP Holdco,” and collectively with El Paso and the Unitholders, the “El Paso Parties”), (b) Enterprise GP Holdings L.P., a Delaware limited partnership (“Enterprise”), and (c) solely for purposes of Section 5.3 of this Agreement, EPCO, Inc., a Texas corporation (“Enterprise Parent”).

WITNESSETH:

     WHEREAS, El Paso owns, directly or indirectly, 100% of the outstanding equity interests in each of El Paso GP Holdco and the Unitholders; and

     WHEREAS, El Paso GP Holdco owns a 9.9% membership interest (the “Membership Interest”) in Enterprise Products GP LLC (“Enterprise GP”), and Enterprise GP is the sole general partner of, and owns 100% of the 2% general partner interest in, Enterprise Products Partners, L.P., a Delaware limited partnership (“Enterprise MLP”); and

     WHEREAS, subject to the terms and conditions set forth herein, El Paso GP Holdco desires to sell to Enterprise, and Enterprise desires to purchase from El Paso GP Holdco, the Membership Interest; and

     WHEREAS, the Unitholders own (beneficially and of record) the number of Enterprise MLP Common Units (as defined below) listed on Schedule 1 hereto; and

     WHEREAS, subject to the terms and conditions hereof, the Unitholders desire to sell to Enterprise, and Enterprise desires to purchase from the Unitholders, all of the Enterprise MLP Common Units owned by the Unitholders; and

     NOW, THEREFORE, in consideration of the premises and the respective representations, warranties, covenants, agreements and conditions contained herein, the parties hereto agree as follows:

ARTICLE I

DEFINITIONS

     Section 1.1 Definitions. In this Agreement, unless the context otherwise requires, the following terms shall have the following meanings respectively:

     “affiliate” has the meaning set forth in Rule 405 of the rules and regulations under the Securities Act, unless otherwise expressly stated herein.

     “Agreement” has the meaning set forth in the Preamble.

1

     “Business Day” means any day on which commercial banks are generally open for business in New York, New York other than a Saturday, a Sunday or a day observed as a holiday in New York, New York under the Laws of the State of New York or the federal Laws of the United States of America.

     “Code” means the Internal Revenue Code of 1986, as amended.

     “Damages” means claims, liabilities, damages, penalties, judgments, assessments, losses, costs, expenses, including reasonable attorneys’ fees and expenses, incurred by the party seeking indemnification under this Agreement.

     “Effective Date” has the meaning set forth in the Preamble.

     “El Paso” has the meaning set forth in the Preamble.

     “El Paso GP Holdco” has the meaning set forth in the Preamble.

     “El Paso Parties” has the meaning set forth in the Preamble.

     “El Paso Sub 1” has the meaning set forth in the Preamble.

     “El Paso Sub 2” has the meaning set forth in the Preamble.

     “Encumbrances” means pledges, restrictions on transfer, proxies and voting or other agreements, liens, claims, charges, mortgages, security interests or other legal or equitable encumbrances, limitations or restrictions of any nature whatsoever, but does not include any restriction on transfer arising or existing under applicable securities laws.

     “Enterprise GP” has the meaning set forth in the Preamble.

     “Enterprise MLP” has the meaning set forth in the recitals.

     “Enterprise MLP Common Units” means the Common Units of Enterprise MLP issued and outstanding pursuant to the Enterprise Partnership Agreement.

2

     “governing documents” means, with respect to any person, the certificate or articles of incorporation, by-laws, articles of organization, limited liability company agreement, partnership agreement, formation agreement, joint venture agreement, unanimous shareholder agreement or declaration or other similar governing documents of such person.

     “Governmental Entity” means any (a) multinational, federal, provincial, territorial, state, regional, municipal, local or other government, governmental or public department, central bank, court, tribunal, arbitral body, commission, board, bureau or agency, domestic or foreign, (b) subdivision, agent, commission, board, or authority of any of the foregoing, or (c) quasi-governmental or private body exercising any regulatory, expropriation or taxing authority under, or for the account of, any of the foregoing.

     “Laws” means all statutes, regulations, statutory rules, orders, judgments, decrees and terms and conditions of any grant of approval, permission, authority, permit or license of any court, Governmental Entity, statutory body (including the NYSE) or self-regulatory authority, but does not include Environmental Laws.

     “Materiality Requirement” means any requirement in a representation or warranty that a condition, event or state of fact be “material,” correct or true in “all material respects,” have a “Material Adverse Effect” or be or not be “reasonably expected to have a Material Adverse Effect” (or other words or phrases of similar effect or impact) in order for such condition, event or state of facts to cause such representation or warranty to be inaccurate.

     “Membership Interest Purchase Price” has the meaning set forth in Section 2.1(b).

     “Permitted Encumbrances” means any liens, title defects, preferential rights or other encumbrances upon any of the relevant person’s property, assets or revenues, whether now owned or hereafter acquired, that are (i) carriers’, warehousemens’, mechanics’, materialmen’s, repairmen’s or other like liens arising in the ordinary course of business which are not overdue for a period of more than 60 days or which are being contested in good faith by appropriate proceeding, (ii) pledges or deposits in connection with workers’ compensation, unemployment insurance and other social security legislation and deposits securing liability to insurance carriers under insurance or self-insurance arrangements, (iii) for taxes not yet due or which are being contested in good faith by appropriate proceedings (provided that adequate reserves with respect thereto are maintained on the books of such person or its subsidiaries, as the case may be, in conformity with GAAP), (iv) deposits to secure the performance of bids, trade contracts (other than for borrowed money), leases, statutory obligations, surety and appeal bonds, performance bonds and other obligations of a like nature incurred in the ordinary course of business, (v) easements, rights-of-way, restrictions and other similar encumbrances incurred in the ordinary course of business which, in the aggregate, are not substantial in amount and which do not in any case materially detract from the value of the property subject thereto or materially interfere with the ordinary conduct of the business by such person and its subsidiaries and (vi) created pursuant to construction, operating and maintenance agreements, space lease

3

agreements and other similar agreements, in each case having ordinary and customary terms and entered into in the ordinary course of business by such person and its subsidiaries.

     “person” includes any individual, firm, partnership, joint venture, venture capital fund, limited liability company, association, trust, estate, group, body corporate, corporation, unincorporated association or organization, Governmental Entity, syndicate or other entity, whether or not having legal status.

     “Solvent” means, with respect to the applicable person on any date of determination, that on such date (a) such applicable person’s property, at a fair valuation, exceeds the sum of such applicable person’s debts, (b) the present fair saleable value of the assets of such applicable person is not less than the amount that will be required to pay its debts as they become absolute and matured, (c) such applicable person does not intend to incur, or believes that such applicable person has not incurred, debts that would be beyond such applicable person’s ability to pay as such debts matured, and (d) such applicable person is not engaged in business or a transaction, and does not intend to engage in business or a transaction, for which such applicable person’s property remaining after such transaction would constitute unreasonably small capital.

     “subsidiary” means with respect to a specified person, any other person (a) that is a subsidiary as defined in Rule 405 of the Rules and Regulations under the Securities Act of such specified person and (b) of which such specified person or another of its subsidiaries owns beneficially more than 50% of the equity interests.

     “Tax” or “Taxes” means any taxes, assessments, fees and other governmental charges imposed by any Governmental Entity, including without limitation income, profits, gross receipts, net proceeds, alternative or add-on minimum, ad valorem, value added, turnover, sales, use, property, personal property (tangible and intangible), environmental, stamp, leasing, lease, user, excise, duty, franchise, capital stock, transfer, registration, license, withholding, social security (or similar), unemployment, disability, payroll, employment, fuel, excess profits, occupational, premium, windfall profit, severance, estimated, or other charge of any kind whatsoever, including any interest, penalty, or addition thereto, whether disputed or not.

     “Tax Return” means any return, declaration, report, claim for refund, or information return or statement relating to Taxes, including any schedule or attachment thereto, and including any amendment thereof.

     “Unit Purchase Price” has the meaning set forth in Section 2.1(c).

     Section 1.2 Rules of Construction. The division of this Agreement into articles, sections and other portions and the insertion of headings are for convenience of reference only and shall not affect the construction or interpretation hereof. Unless otherwise indicated, all references to an “Article” or “Section” followed by a number or a letter refer to the specified Article or Section of this Agreement. The terms “this Agreement,” “hereof,” “herein” and “hereunder” and similar expressions refer to this Agreement (including the Disclosure Letters hereto) and not to any particular Article, Section or other portion hereof. Unless otherwise specifically indicated or the context otherwise requires, (a) all references to “dollars” or “$” mean United States dollars, (b) words importing the singular shall include the plural and vice

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versa and words importing any gender shall include all genders, (c) “include,” “includes” and “including” shall be deemed to be followed by the words “without limitation,” and (d) all words used as accounting terms shall have the meanings assigned to them under United States generally accepted accounting principles applied on a consistent basis during the periods involved (“GAAP”). In the event that any date on which any action is required to be taken hereunder by any of the parties hereto is not a Business Day, such action shall be required to be taken on the next succeeding day that is a Business Day. Reference to any party hereto is also a reference to such party’s permitted successors and assigns. The Exhibits attached to this Agreement are hereby incorporated by reference into this Agreement and form part hereof. Unless otherwise indicated, all references to an “Exhibit” followed by a number or a letter refer to the specified Exhibit to this Agreement. The parties hereto have participated jointly in the negotiation and drafting of this Agreement. In the event an ambiguity or question of intent or interpretation arises, this Agreement shall be construed as if drafted jointly by the parties hereto and no presumption or burden of proof shall arise favoring or disfavoring any party hereto by virtue of the authorship of any of the provisions of this Agreement.

ARTICLE II

PURCHASE AND SALE

     Section 2.1 Closing.

          (a) Closing Date. The closing (the “Closing”) of the transactions contemplated under this Section 2.1 shall be held at the offices of Enterprise at 2727 North Loop West, Houston, Texas 77008 on the Effective Date. The “Closing Date,” as referred to herein, shall mean the date of the Closing.

          (b) Purchase of the Membership Interest. On the Closing Date, El Paso GP Holdco shall, and El Paso shall cause El Paso GP Holdco to, convey to Enterprise the Membership Interest (such conveyance or assignment to be in a form mutually acceptable to El Paso GP Holdco and Enterprise), free and clear of all Encumbrances (other than those set forth in the governing documents of Enterprise GP in existence immediately prior to the Closing) for an aggregate cash amount equal to $97,060,737.05 (such aggregate cash amount, the “Membership Interest Purchase Price”).

          (c) Purchase and Sale of EPD Common Units. On the Closing Date and immediately after the consummation of the transactions described in Section 2.1(b) of this Agreement, (i) El Paso Sub 1 shall, and El Paso shall cause El Paso Sub 1 to, sell to Enterprise, and Enterprise shall purchase from El Paso Sub 1, 8,347,868 Enterprise MLP Common Units, for an aggregate cash amount of $203,604,500.52 (the “Sub 1 Purchase Price”), and (ii) El Paso Sub 2 shall, and El Paso shall cause El Paso Sub 2 to, sell to Enterprise, and Enterprise shall purchase from El Paso Sub 2, a total of 5,106,630 Enterprise MLP Common Units for an aggregate cash amount of $124,550,705.70 (the “Sub 2 Purchase Price”, and together with the Sub 1 Purchase Price, collectively or individually, as the context may require, the “Unit Purchase Price”).

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          (d) Deliveries at the Closing. At the Closing:

               (i) El Paso GP Holdco shall execute and deliver to Enterprise an assignment agreement, in form and substance mutually satisfactory to El Paso GP Holdco and Enterprise, pursuant to which El Paso GP Holdco transfers and assigns the Membership Interest to Enterprise free and clear of any Encumbrance (other than those set forth in the governing documents of Enterprise GP in existence immediately prior to the Closing;

               (ii) El Paso Sub 1 shall sell, transfer and convey to Enterprise 8,347,868 Enterprise MLP Common Units, and El Paso Sub 2, shall sell, transfer and convey to Enterprise 5,106,630 Enterprise MLP Common Units, in each case, free and clear of any Encumbrance and, in each case, pursuant to an assignment, in form mutually satisfactory to the applicable Unitholder and Enterprise; and

               (iii) Enterprise shall pay, or cause to be paid, to (i) El Paso GP Holdco, an amount in cash equal to the Membership Interest Purchase Price, (ii) El Paso Sub 1, an amount in cash equal to the Sub 1 Purchase Price and (iii) El Paso Sub 2 an aggregate amount of cash equal to the Sub 2 Purchase Price, such payments to be made by wire transfer of immediately available funds to the accounts specified below:

Payments to El Paso GP Holdco:
	Bank:	Mellon Bank
		Pittsburgh, PA
	Account Name:	GulfTerra GP Holding Company
	Account Number:	008-6641
	ABA#	043 000 261
Payments to El Paso Sub I and El Paso Sub 2:
	Bank:	Mellon Bank
		Pittsburgh, PA
	Account Name:	El Paso Corporation
	Account Number:	040-2173
	ABA#	043 000 261

ARTICLE III

REPRESENTATIONS AND WARRANTIES

     Section 3.1 Representations and Warranties of El Paso and El Paso GP Holdco. Each of El Paso and El Paso GP Holdco, jointly and severally, represents and warrants to Enterprise that:

          (a) Formation and Standing. Each of El Paso GP Holdco and El Paso has been duly formed and is validly existing under the Laws of its jurisdiction of organization or formation with full legal or corporate power and authority to own, lease and operate its properties and to conduct its businesses as currently owned and conducted except where,

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individually or in the aggregate, the failure to be so organized, formed or existing or to have such power or authority could not reasonably be expected to have a material adverse effect on the ability of El Paso and/or El Paso GP Holdco to close the transactions contemplated under this Agreement. Each of El Paso GP Holdco and El Paso is duly qualified to do business in each jurisdiction in which the nature of the business conducted by it or the ownership or leasing of its properties requires it to so qualify, except where, individually or in the aggregate, the failure to be so qualified could not reasonably be expected to have a material adverse effect on the ability of El Paso and/or El Paso GP Holdco to close the transactions contemplated under this Agreement.

          (b) Authority and No Conflicts. (i) Each of El Paso and El Paso GP Holdco has all requisite corporate power and authority to enter into this Agreement and to perform its obligations hereunder and to consummate the transactions contemplated hereby. The execution and delivery of this Agreement by each of El Paso and El Paso GP Holdco and the consummation by each of El Paso and El Paso GP Holdco of the transactions contemplated by this Agreement have been duly and validly authorized by all necessary corporate action on the part of El Paso and no other corporate proceedings on the part of El Paso GP Holdco or El Paso are necessary to authorize this Agreement or to consummate the transactions contemplated hereby.

               (ii) This Agreement has been duly executed and delivered by each of El Paso GP Holdco and El Paso and constitutes its legal, valid and binding obligation, enforceable against it in accordance with its terms, except as the same may be limited by bankruptcy, insolvency and other applicable Laws affecting creditors’ rights generally, and by general principles of equity.

               (iii) Neither the execution and delivery of this Agreement by El Paso or El Paso GP Holdco nor the performance by El Paso or El Paso GP Holdco of its obligations hereunder and the completion of the transactions contemplated hereby, will:

                    (A) conflict with, or violate any provision of, the governing documents of El Paso GP Holdco or El Paso;

                    (B) other than obtaining or making, as applicable, any consents, approvals, orders, authorizations, registrations, declarations or filings which, if not obtained or made, could not, individually or in the aggregate, reasonably be expected to have a material adverse effect on the ability of El Paso or El Paso GP Holdco to close the transactions contemplated under this Agreement, violate or breach any Laws applicable to El Paso GP Holdco or El Paso;

                    (C) other than obtaining or making, as applicable, any other consents, approvals, orders, authorizations, registrations, declarations or filings which, if not obtained or made, could not, individually or in the aggregate, reasonably be expected to have a material adverse effect on the ability of El Paso GP Holdco or El Paso to close the transactions contemplated under this Agreement, violate or conflict with or result in the breach of, or constitute a default (or an event that with the giving of notice, the passage of time, or both would constitute a default) under, or entitle any party (with the giving of notice, the passage of time or

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both) to terminate, accelerate, modify or call any obligations or rights under any credit agreement, note, bond, mortgage, indenture, deed of trust, contract, agreement, lease, license, franchise, permit, concession, easement or other instrument to which El Paso GP Holdco or El Paso is a party or by which El Paso GP Holdco, on the one hand, or El Paso or any of its subsidiaries, on the other hand, or their respective properties are bound or subject; or

                    (D) result in the imposition of any Encumbrance upon, or require the sale or give any person the right to acquire any of the assets of El Paso GP Holdco or any of the material assets of El Paso or restrict, hinder, impair or limit the ability of El Paso GP Holdco or El Paso to carry on its business as and where it is now being carried on, except where such imposition, requirement, right, restriction, hindrance, improvement or limit, individually or in the aggregate, could not reasonably be expected to have an adverse effect on the ability of El Paso GP Holdco or El Paso to close the transactions contemplated under this Agreement.

          (c) Membership Interest. El Paso GP Holdco owns the Membership Interest. The Membership Interest is held of record and beneficially by El Paso GP Holdco, free and clear of Encumbrances (other than those set forth in the governing documents of Enterprise GP).

          (d) No Defaults. Neither El Paso GP Holdco nor El Paso is in default under or violation of, and there has been no event, condition or occurrence which, after notice or lapse of time or both, would constitute such a default or violation of, or permit the termination of, any term, condition or provision of (i) their respective governing documents, (ii) any credit agreement, note, bond, mortgage, indenture, contract, agreement, lease, license, franchise, permit, concession, easement or other instrument to which El Paso GP Holdco or El Paso is a party or by which El Paso GP Holdco or El Paso or any of their respective property is bound or subject, except, in the case of clause (ii), for defaults, violations and terminations which, individually or in the aggregate, could not reasonably be expected to have a material adverse effect on the ability of El Paso GP Holdco or El Paso to close the transactions contemplated under this Agreement.

          (e) Solvency. Each of El Paso and El Paso GP Holdco is, and immediately after giving effect to the transactions contemplated by this Agreement will be, Solvent.

          (f) Brokerage and Finder’s Fee. None of El Paso, El Paso GP Holdco or any of their affiliates has incurred or will incur on behalf of El Paso, El Paso GP Holdco or any affiliate thereof any brokerage, finders’ or similar fee in connection with the transactions contemplated by this Agreement for which Enterprise or Enterprise MLP or any of their respective affiliates will be, or could be, obligated.

     Section 3.2 Representations and Warranties of El Paso and the Unitholders. Each of El Paso and each Unitholder, jointly and severally, represents and warrants to Enterprise that:

          (a) Ownership, Etc. of Units. Each Unitholder is the record or beneficial owner of the Enterprise MLP Common Units listed across from the name of such Unitholder on Schedule 1 hereto. Such Enterprise MLP Common Units are the only equity interests of Enterprise MLP that are owned (either beneficially or of record) by such Unitholder. Such Unitholder holds such Enterprise MLP Common Units free and clear of all Encumbrances.

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          (b) Authority. Each of the Unitholders has all requisite limited liability company power and authority to enter into this Agreement and to perform its obligations hereunder and to consummate the transactions contemplated by this Agreement. The execution and delivery of this Agreement by the Unitholders and the consummation by the Unitholders of the transactions contemplated by this Agreement have been duly and validly authorized by all necessary limited liability company action and no other limited liability company proceedings on the part of any of the Unitholders are necessary to authorize this Agreement or to consummate the transactions contemplated hereby.

          (c) Execution and Delivery. This Agreement has been duly executed and delivered by each of the Unitholders and constitutes their respective legal, valid and binding obligation, enforceable against it in accordance with its terms, except as the same may be limited by bankruptcy, insolvency and other applicable Laws affecting creditors’ rights generally, and by general principles of equity.

          (d) Non-Contravention. Neither the execution and delivery of this Agreement by any of the Unitholders nor the performance by any of them of their obligations hereunder or thereunder and the completion of the transactions contemplated hereby or thereby will:

               (i) conflict with, or violate any provision of, the governing documents of the Unitholders;

               (ii) other than obtaining or making, as applicable, any other consents, approvals, orders, authorizations, registrations, declarations or filings which, if not obtained or made, could not, individually or in the aggregate, reasonably be expected to have a material adverse effect on the ability of the Unitholders to consummate the transactions contemplated by this Agreement, violate or breach any applicable Laws;

               (iii) other than obtaining or making, as applicable, any other consents, approvals, orders, authorizations, registrations, declarations or filings which, if not obtained or made, could not, individually or in the aggregate, reasonably be expected to have a material adverse effect on the ability of the Unitholders to consummate the transactions contemplated by this Agreement, violate or conflict with or result in the breach of, or constitute a default (or an event that with the giving of notice, the passage of time, or both would constitute a default) under, or entitle any party (with the giving of notice, the passage of time or both) to terminate, accelerate, modify or call any obligations or rights under any credit agreement, note, bond, mortgage, indenture, deed of trust, contract, agreement, lease, license, franchise, permit, concession, easement or other instrument to which any of the Unitholders is a party or by which any of the Unitholders or their property is bound or subject; or

               (iv) result in the imposition of any Encumbrance upon or require the sale or give any person the right to acquire any of the assets of any of the Unitholders, other than the transactions contemplated by this Agreement, or restrict, hinder, impair or limit the ability of any of the Unitholders to carry on their businesses as and where they are now being carried on.

          (e) No Defaults. None of the Unitholders is in default under or violation of, and there has been no event, condition or occurrence which, after notice or lapse of time or both,

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would constitute such a default or violation of, or permit the termination of, any term, condition or provision of (i) their respective governing documents, (ii) any credit agreement, note, bond, mortgage, indenture, contract, agreement, lease, license, franchise, permit, concession, easement or other instrument to which any of the Unitholders is a party or by which any of the Unitholders or any of their property is bound or subject, except, in the case of clause (ii), for defaults, violations and terminations which, individually or in the aggregate, could not reasonably be expected to have a material adverse effect on the ability of the Unitholders to consummate the transactions contemplated by this Agreement.

     Section 3.3 Representations and Warranties of Enterprise Concerning the Transaction. Enterprise represents and warrants to El Paso, El Paso GP Holdco and the Unitholders that:

          (a) Organization and Standing. Enterprise has been duly organized and is validly existing under the Laws of its jurisdiction of organization with full legal or partnership power and authority to own, lease and operate its properties and to conduct its businesses as currently owned and conducted except where, individually or in the aggregate, the failure of to be so organized or existing or to have such power or authority could not reasonably be expected to have a material adverse effect on the ability of Enterprise to close the transactions contemplated under this Agreement. Enterprise is duly qualified to do business in each jurisdiction in which the nature of the business conducted by it or the ownership or leasing of its properties requires it to so qualify, except where, individually or in the aggregate, the failure to be so qualified could not reasonably be expected to have a material adverse effect on the ability of Enterprise to close the transactions contemplated under this Agreement.

          (b) Authority and No Conflicts.

               (i) Enterprise has all requisite partnership power and authority to enter into this Agreement and to perform its obligations hereunder and to consummate the transactions contemplated hereby. The execution and delivery of this Agreement by Enterprise and the consummation thereby of the transactions contemplated by this Agreement have been duly and validly authorized by all necessary partnership action and no other proceedings on the part of Enterprise are necessary to authorize this Agreement or to consummate the transactions contemplated hereby.

               (ii) This Agreement has been duly executed and delivered by Enterprise and constitutes its legal, valid and binding obligation, enforceable against it in accordance with its terms, except as the same may be limited by bankruptcy, insolvency and other applicable Laws affecting creditors’ rights generally, and by general principles of equity.

               (iii) Neither the execution and delivery of this Agreement by Enterprise nor the performance by Enterprise of its obligations hereunder and the completion of the transactions contemplated hereby, will:

                    (A) conflict with, or violate any provision of, the governing documents of Enterprise;

                    (B) other than obtaining or making, as applicable, any other consents, approvals, orders, authorizations, registrations, declarations or filings which, if not

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obtained or made, could not, individually or in the aggregate, reasonably be expected to have a material adverse effect on the ability of Enterprise to close the transactions contemplated under this Agreement, violate or breach any Laws applicable to Enterprise;

                    (C) other than obtaining or making, as applicable, any other consents, approvals, orders, authorizations, registrations, declarations or filings which, if not obtained or made, could not, individually or in the aggregate, reasonably be expected to have a material adverse effect on the ability of Enterprise to close the transactions contemplated under this Agreement, violate or conflict with or result in the breach of, or constitute a default (or an event that with the giving of notice, the passage of time, or both would constitute a default) under, or entitle any party (with the giving of notice, the passage of time or both) to terminate, accelerate, modify or call any obligations or rights under any credit agreement, note, bond, mortgage, indenture, deed of trust, contract, agreement, lease, license, franchise, permit, concession, easement or other instrument to which Enterprise is a party or by which Enterprise or its property is bound or subject; or

                    (D) except as could not, individually or in the aggregate, reasonably be expected to have a material adverse effect on the ability of Enterprise to close the transactions contemplated under this Agreement, result in the imposition of any Encumbrance upon or require the sale or give any person the right to acquire any of the assets of Enterprise or restrict, hinder, impair or limit the ability of Enterprise to carry on its business as and where it is now being carried on.

          (c) No Defaults. Enterprise is not in default under or in violation of, and there has been no event, condition or occurrence which, after notice or lapse of time or both, would constitute such a default or violation of, or permit the termination of, any term, condition or provision of (i) its governing documents, (ii) any credit agreement, note, bond, mortgage, indenture, contract, agreement, lease, license, franchise, permit, concession, easement or other instrument to which Enterprise is a party or by which Enterprise any of its property is bound or subject, except, in the case of clause (ii), for defaults, violations and terminations which, individually or in the aggregate, could not reasonably be expected to have a material adverse effect on the ability of Enterprise to close the transactions contemplated under this Agreement.

          (d) Brokerage and Finder’s Fee. None of Enterprise, its affiliates nor any shareholder, director, officer or employee thereof, has incurred or will incur on behalf of Enterprise, any brokerage, finders’ or similar fee in connection with the transactions contemplated by this Agreement for which any of the El Paso Parties or their affiliates will be obligated.

          (e) Investment Intent; Investment Experience; Restricted Securities. In acquiring the Membership Interest and the Enterprise MLP Common Units to be purchased from the Unitholders, Enterprise is not offering or selling, and shall not offer or sell the Membership Interest or such Enterprise MLP Common Units, in connection with any distribution of any of such Membership Interest or such Enterprise MLP Common Units, and Enterprise has no participation and shall not participate in any such undertaking or in any underwriting of such an undertaking except in compliance with applicable federal and state securities laws. Enterprise acknowledges that it is able to fend for itself, can bear the economic risk of its investment in the

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Membership Interest and such Enterprise MLP Common Units and has such knowledge and experience in financial and business matters that it is capable of evaluating the merits and risks of an investment in the Membership Interest and such Enterprise MLP Common Units.

ARTICLE IV

COVENANTS AND AGREEMENTS

     Section 4.1 Commercially Reasonable Efforts; Further Assurances. Subject to the other terms of this Agreement, the parties hereto agree that, from time to time, whether before, at or after the Closing Date, each of them will execute and deliver, or cause to be executed and delivered, such instruments of assignment, transfer, conveyance, endorsement, direction or authorization as may be necessary to consummate and make effective such transactions.

     Section 4.2 Intentionally Omitted

     Section 4.3 Expenses. All costs and expenses incurred in connection with this Agreement, including legal fees, accounting fees, financial advisory fees and other professional and non-professional fees and expenses, shall be paid by the party hereto incurring such expenses.

ARTICLE V

REMEDIES FOR DEFAULT

     Section 5.1 Indemnity Regarding Section 3.1 Representations and Covenants. Subject to the provisions of this Article V, El Paso and El Paso GP Holdco shall indemnify and hold harmless Enterprise and its affiliates from any and all Damages incurred by Enterprise or any of its affiliates in connection with the breach of a representation or warranty set forth in Section 3.1 or a covenant or agreement made by El Paso or El Paso GP Holdco hereunder; provided, however, that in no event shall El Paso and El Paso GP Holdco be liable under this Section 5.1 for an aggregate amount of Damages in excess of the Membership Interest Purchase Price.

     Section 5.2 Indemnity Regarding Section 3.2 Representations and Covenants. Subject to the provisions of this Article V, El Paso and the Unitholders shall indemnify and hold

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harmless Enterprise and its affiliates from any and all Damages incurred by Enterprise or any of its affiliates in connection with the breach of a representation or warranty set forth in Section 3.2 or a covenant or agreement made by the Unitholders hereunder; provided, however, that in no event shall El Paso and the Unitholders be liable under this Section 5.2 for an aggregate amount of Damages in excess of the Unit Purchase Price.

     Section 5.3 Indemnity Regarding Section 3.3 Representations and Covenants. Subject to the provisions of this Article V, Enterprise and Enterprise Parent shall indemnify and hold harmless the El Paso Parties and their respective affiliates from any and all Damages incurred by any such party or any of their respective affiliates in connection with the breach of a representation or warranty set forth in Section 3.3 or a covenant or agreement made by Enterprise hereunder.

     Section 5.4 Survival of Representations. The representations, warranties, covenants and agreements contained in this Agreement or made in any certificate or document delivered pursuant hereto shall survive the Closing regardless of any investigation made by the parties hereto and regardless of any knowledge acquired or capable of being acquired whether before or after the Closing Date.

     Section 5.5 Enforcement of this Agreement. The parties hereto acknowledge and agree that an award of money damages would be inadequate for any breach of this Agreement by any party and any such breach would cause the non-breaching parties irreparable harm. Accordingly, the parties hereto agree that, in the event of any breach or threatened breach of this Agreement by one of the parties, the parties will also be entitled, without the requirement of posting a bond or other security, to equitable relief, including injunctive relief and specific performance, provided such party is not in material default hereunder. Such remedies will not be the exclusive remedies for any breach of this Agreement but will be in addition to all other remedies available at law or equity to each of the parties.

     Section 5.6 Exclusive Remedy . Except as set forth in Section 5.8, the parties agree that the indemnification provisions in this Article V shall be the exclusive remedy of the parties with respect to breaches of representations and warranties and failures to perform covenants or agreements hereunder.

     Section 5.7 General Limitation of Damages . NOTWITHSTANDING ANY OTHER PROVISION OF THIS AGREEMENT TO THE CONTRARY, EXCEPT AS SET FORTH IN SECTION 5.8, ENTERPRISE AND ITS AFFILIATES SHALL NOT BE LIABLE TO THE EL PASO PARTIES AND THEIR AFFILIATES, NOR SHALL THE EL PASO PARTIES AND THEIR AFFILIATES BE LIABLE TO ENTERPRISE OR ITS AFFILIATES, FOR ANY EXEMPLARY, PUNITIVE, SPECIAL, INDIRECT, CONSEQUENTIAL, REMOTE OR SPECULATIVE DAMAGES (INCLUDING ANY DAMAGES ON ACCOUNT OF LOST PROFITS OR OPPORTUNITIES) ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY.

     Section 5.8 No Waiver Relating to Claims for Fraud/Willful Misconduct. The liability of any party under this Article V shall be in addition to, and not exclusive of, any other liability that such party may have at law or in equity based on such party’s (a) fraudulent acts or

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omissions or (b) willful misconduct. None of the provisions set forth in this Agreement shall be deemed to be a waiver by or release of any party of any right or remedy which such party may have at law or equity based on any other party’s fraudulent acts or omissions or willful misconduct nor shall any such provisions limit, or be deemed to limit, (i) the amounts of recovery sought or awarded in any such claim for fraud or willful misconduct, (ii) the time period during which a claim for fraud or willful misconduct may be brought, or (iii) the recourse which any such party may seek against another party with respect to a claim for fraud or willful misconduct.

ARTICLE VI

MISCELLANEOUS

     Section 6.1 Notices . Any notice,request, instruction, correspondence or other document to be given hereunder by any party to another party (each, a “Notice”) shall be in writing and delivered in person or by courier service requiring acknowledgment of receipt of delivery or mailed by U.S. registered or certified mail, postage prepaid and return receipt requested, or by telecopier, as follows; provided, that copies to be delivered below shall not be required for effective notice and shall not constitute effective notice:

If to any of El Paso, El Paso GP Holdco
or any of the Unitholders, addressed to:

El Paso Corporation
El Paso Building
1001 Louisiana
Houston, Texas 77002
Attention: General Counsel
Telecopy: (713) 420-2813

If to Enterprise, addressed to:

Enterprise GP Holdings L.P.
2727 North Loop West
Houston, Texas 77008
Attention: Chief Legal Officer
Telecopy: (713) 880-6570

     Notice given by personal delivery, courier service or mail shall be effective upon actual receipt. Notice given by telecopier shall be confirmed by appropriate answer back and shall be effective upon actual receipt if received during the recipient’s normal business hours, or at the beginning of the recipient’s next business day after receipt if not received during the recipient’s normal business hours. All Notices by telecopier shall be confirmed promptly after transmission in writing by certified mail or personal delivery. Any party may change any address to which Notice is to be given to it by giving Notice as provided above of such change of address.

     Section 6.2 Governing Law; Jurisdiction; Waiver of Jury Trial. To the maximum extent permitted by applicable Law, the provisions of this agreement shall be governed by and

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construed and enforced in accordance with the laws of the State of Delaware, without regard to principles of conflicts of law. Each party thereto hereby irrevocably and unconditionally (a) consents and submits to the exclusive jurisdiction of any federal or state court located in the State of Texas (the “Texas Courts”) for any actions, suits or proceedings arising out of or relating to this Agreement or the transactions contemplated by this Agreement (and agrees not to commence any litigation relating thereto except in such courts), (b) waives any objection to the laying of venue of any such litigation in the Texas Courts and agrees not to plead or claim in any Texas Court that such litigation brought therein has been brought in any inconvenient forum and (c) acknowledges and agrees that any controversy which may arise under this Agreement is likely to involve complicated and difficult issues, and therefore each such party hereby irrevocably and unconditionally waives any right such party may have to a trial by jury in respect of any litigation directly or indirectly arising or relating to this Agreement or the transactions contemplated by this Agreement.

     Section 6.3 Entire Agreement; Amendments and Waivers. This Agreement constitutes the entire agreement between and among the parties hereto pertaining to the subject matter hereof and supersedes all prior agreements, understandings, negotiations and discussions, whether oral or written, of the parties, and there are no warranties, representations or other agreements between or among the parties in connection with the subject matter hereof except as set forth specifically herein or contemplated hereby. No supplement, modification or waiver of this Agreement shall be binding unless executed in writing by the party to be bound thereby. The failure of a party to exercise any right or remedy shall not be deemed or constitute a waiver of such right or remedy in the future. No waiver of any of the provisions of this Agreement shall be deemed or shall constitute a waiver of any other provision hereof (regardless of whether similar), nor shall any such waiver constitute a continuing waiver unless otherwise expressly provided.

     Section 6.4 Binding Effect and Assignment. This Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective permitted successors and assigns. Nothing in this Agreement, express or implied, is intended to confer upon any person other than the parties hereto and their respective permitted successors and assigns, any rights, benefits or obligations hereunder. No party hereto may assign, transfer, dispose of or otherwise alienate this Agreement or any of its rights, interests or obligations under this Agreement (whether by operation of law or otherwise). Any attempted assignment, transfer, disposition or alienation in violation of this Agreement shall be null, void and ineffective.

     Section 6.5 Severability. If any term or other provision of this Agreement is invalid, illegal, or incapable of being enforced by any rule of applicable Law, or public policy, all other conditions and provisions of this Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated herein are not affected in any manner materially adverse to any party hereto. Upon such determination that any term or other provision is invalid, illegal, or incapable of being enforced, the parties hereto shall negotiate in good faith to modify this Agreement so as to effect the original intent of the parties hereto as closely as possible in a mutually acceptable manner in order that the transactions contemplated herein are consummated as originally contemplated to the fullest extent possible.

15

     Section 6.6 Execution. This Agreement may be executed in multiple counterparts each of which shall be deemed an original and all of which shall constitute one instrument.

[The remainder of this page is blank]

16

     IN WITNESS WHEREOF, the parties hereto have entered into this Agreement as of the date first written above.

EL PASO CORPORATION

By:

Name:

Title:

GULFTERRA GP HOLDING COMPANY

By:

Name:

Title:

SABINE RIVER INVESTORS I, L.L.C.

By:

Name:

Title:

SABINE RIVER INVESTORS II, L.L.C.

By:

Name:

Title:

ENTERPRISE GP HOLDINGS L.P.

By: EPE Holdings, LLC, General Partner

By:

Name:

Title:

17

EPCO, INC. (solely for purposes of Section 5.3 of
this Agreement)

By:

Name:

Title:

18

SCHEDULE 1

Name and Address of	Number of
Unitholder	Enterprise MLP Common Units
EL PASO SUB 1:
Sabine River Investors I, L.L.C.	8,347,868
El Paso Building
1001 Louisiana
Houston, Texas 77002
Attention: General Counsel
EL PASO SUB 2:
Sabine River Investors II, L.L.C.	5,106,630
El Paso Building
1001 Louisiana
Houston, Texas 77002
Attention: General Counsel

Schedule 1-1

EX-4.A

EXHIBIT 4.A

EL PASO ENERGY CORPORATION

TO

THE CHASE MANHATTAN BANK

TRUSTEE

INDENTURE

DATED AS OF MAY 10, 1999

SENIOR DEBT SECURITIES

EL PASO ENERGY CORPORATION

CERTAIN SECTIONS OF THIS INDENTURE RELATING TO

SECTIONS 310 THROUGH 318, INCLUSIVE, OF THE

TRUST INDENTURE ACT OF 1939:

Trust Indenture Act Section	Indenture Section
Section 310(a)(1)			6.9
(a)(2)			6.9
(a)(3)	Not Applicable
(a)(4)	Not Applicable
(b)		6.8; 6.10
Section 311(a)			6.13
(b)			6.13
Section 312(a)		7.1; 7.2
(b)			7.2
(c)			7.2
Section 313(a)			7.3
(b)			7.3
(c)			7.3
(d)			7.3
Section 314(a)			7.4
(a)(4)		1.4; 10.4
(b)	Not Applicable
(c)(1)			1.1
(c)(2)		1.1; 1.2
(c)(3)	Not Applicable
(d)	Not Applicable
(e)			1.2
Section 315(a)			6.1
(b)			6.2
(c)			6.1
(d)			6.1
(e)			5.14
Section 316(a)			1.1
(a)(1)(A)		5.2; 5.12
(a)(1)(B)			5.13
(a)(2)	Not Applicable
(b)			5.8
(c)			1.4
(Section) 317(a)(1)			5.3

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Trust Indenture
Act Section	Indenture Section
(a)(2)		5.4
(b)		10.3
Section 318(a)		1.7

NOTE: This reconciliation and tie shall not, for any purpose, be deemed to be a part of the Indenture.

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TABLE OF CONTENTS

PARTIES	1
RECITALS OF THE COMPANY	1
ARTICLE ONE
DEFINITIONS AND OTHER PROVISIONS OF GENERAL APPLICATION	1
SECTION 101. Definitions	1
SECTION 102. Compliance Certificates and Opinions	9
SECTION 103. Form of Documents Delivered to Trustee	10
SECTION 104. Acts of Holders; Record Dates	10
SECTION 105. Notices, Etc., to Trustee and Company	11
SECTION 106. Notice to Holders; Waiver	12
SECTION 107. Conflict with Trust Indenture Act	12
SECTION 108. Effect of Headings and Table of Contents	12
SECTION 109. Successors and Assigns	13
SECTION 110. Separability Clause	13
SECTION 111. Benefits of Indenture	13
SECTION 112. Governing Law	13
SECTION 113. Legal Holidays	13
SECTION 114. Language of Notices, Etc	13
SECTION 115. Incorporators, Stockholders, Officers and Directors of the Company Exempt from Individual Liability	14
ARTICLE TWO
SECURITY FORMS	14
SECTION 201. Forms Generally	14
SECTION 202. Form of Face of Security	14
SECTION 203. Form of Reverse of Security	17
SECTION 204. Global Securities	22
SECTION 205. Form of Trustee’s Certificate of Authentication	23
ARTICLE THREE
THE SECURITIES	23
SECTION 301. Amount Unlimited; Issuable in Series	23
SECTION 302. Denominations	26
SECTION 303. Execution, Authentication, Delivery and Dating	26
SECTION 304. Temporary Securities	28

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SECTION 305. Registration, Registration of Transfer and Exchange	28
SECTION 306. Mutilated, Destroyed, Lost and Stolen Securities	30
SECTION 307. Payment of Interest; Interest Rights Preserved	31
SECTION 308. Persons Deemed Owners	32
SECTION 309. Cancellation	32
SECTION 310. Computation of Interest	33
SECTION 311. CUSIP Numbers	33
ARTICLE FOUR
SATISFACTION AND DISCHARGE	33
SECTION 401. Satisfaction and Discharge of Indenture	33
SECTION 402. Application of Trust Money	34
ARTICLE FIVE
REMEDIES	35
SECTION 501. Events of Default	35
SECTION 502. Acceleration of Maturity; Rescission and Annulment	36
SECTION 503. Collection of Indebtedness and Suits for Enforcement by Trustee	37
SECTION 504. Trustee May File Proofs of Claim	37
SECTION 505. Trustee May Enforce Claims Without Possession of Securities	38
SECTION 506. Application of Money Collected	38
SECTION 507. Limitation on Suits	38
SECTION 508. Unconditional Right of Holders to Receive Principal, Premium and Interest	39
SECTION 509. Restoration of Rights and Remedies	39
SECTION 510. Rights and Remedies Cumulative	40
SECTION 511. Delay or Omission Not Waiver	40
SECTION 512. Control by Holders	40
SECTION 513. Waiver of Past Defaults	40
SECTION 514. Undertaking for Costs	41
SECTION 515. Waiver of Usury, Stay or Extension Laws	41
ARTICLE SIX
THE TRUSTEE	41
SECTION 601. Certain Duties and Responsibilities	41
SECTION 602. Notice of Defaults	42
SECTION 603. Certain Rights of Trustee	42
SECTION 604. Not Responsible for Recitals or Issuance of Securities	43
SECTION 605. May Hold Securities	43
SECTION 606. Money Held in Trust	43

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SECTION 607. Compensation and Reimbursement	44
SECTION 608. Disqualification; Conflicting Interests	44
SECTION 609. Corporate Trustee Required; Eligibility	45
SECTION 610. Resignation and Removal; Appointment of Successor	45
SECTION 611. Acceptance of Appointment by Successor	46
SECTION 612. Merger, Conversion, Consolidation or Succession to Business	47
SECTION 613. Preferential Collection of Claims Against Company	48
SECTION 614. Appointment of Authenticating Agent	48
ARTICLE SEVEN
HOLDERS’ LISTS AND REPORTS BY TRUSTEE AND COMPANY	49
SECTION 701. Company to Furnish Trustee Names and Addresses of Holders	49
SECTION 702. Preservation of Information; Communications to Holders	50
SECTION 703. Reports by Trustee	50
SECTION 704. Reports by Company	51
ARTICLE EIGHT
CONSOLIDATION, MERGER, CONVEYANCE, TRANSFER OR LEASE	51
SECTION 801. Company May Consolidate, Etc., Only on Certain Terms	51
SECTION 802. Successor Substituted	52
ARTICLE NINE
SUPPLEMENTAL INDENTURES	52
SECTION 901. Supplemental Indentures Without Consent of Holders	52
SECTION 902. Supplemental Indentures with Consent of Holders	53
SECTION 903. Execution of Supplemental Indentures	54
SECTION 904. Effect of Supplemental Indentures	54
SECTION 905. Conformity with Trust Indenture Act	55
SECTION 906. Reference in Securities to Supplemental Indentures	55
ARTICLE TEN
COVENANTS	55
SECTION 1001. Payment of Principal, Premium and Interest	55
SECTION 1002. Maintenance of Office or Agency	55
SECTION 1003. Money for Securities Payments to Be Held in Trust	56
SECTION 1004. Statement by Officers as to Default	57
SECTION 1005. Existence	57
SECTION 1006. Limitations on Liens	57
SECTION 1007. Restriction of Sale-Leaseback Transaction	59

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SECTION 1008. Waiver of Certain Covenants	60
ARTICLE ELEVEN
REDEMPTION OF SECURITIES	61
SECTION 1101. Applicability of Article	61
SECTION 1102. Election to Redeem; Notice to Trustee	61
SECTION 1103. Selection by Trustee of Securities to be Redeemed	61
SECTION 1104. Notice of Redemption	62
SECTION 1105. Deposit of Redemption Price	62
SECTION 1106. Securities Payable on Redemption Date	62
SECTION 1107. Securities Redeemed in Part	63
ARTICLE TWELVE
SINKING FUNDS	63
SECTION 1201. Applicability of Article	63
SECTION 1202. Satisfaction of Sinking Fund Payments with Securities	64
SECTION 1203. Redemption of Securities for Sinking Fund	64
ARTICLE THIRTEEN
DEFEASANCE	64
SECTION 1301. Applicability of Article	64
SECTION 1302. Legal Defeasance	64
SECTION 1303. Covenant Defeasance	66
SECTION 1304. Application by Trustee of Funds Deposited for Payment of Securities	67
SECTION 1305. Repayment to Company	67

NOTE: This Table of Contents shall not, for any purpose, be deemed to be a part of the Indenture.

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     INDENTURE dated as of May 10, 1999, between EL PASO ENERGY CORPORATION, a corporation duly organized and existing under the laws of Delaware (the “Company”), having its principal office at the El Paso Energy Building, 1001 Louisiana Street, Houston, Texas 77002, and THE CHASE MANHATTAN BANK, a New York banking corporation, as Trustee (the “Trustee”).

RECITALS OF THE COMPANY

     The Company has duly authorized the execution and delivery of this Indenture to provide for the issuance from time to time of its unsecured debentures, notes or other evidences of indebtedness (the “Securities”), to be issued in one or more series as in this Indenture provided.

     All things necessary to make this Indenture a valid agreement of the Company, in accordance with its terms, have been done.

     This Indenture is subject to the provisions of the Trust Indenture Act that are required to be a part of this Indenture and, to the extent applicable, shall be governed by such provisions.

     NOW, THEREFORE, THIS INDENTURE WITNESSETH:

     For and in consideration of the premises and the purchase of the Securities by the Holders thereof, it is mutually agreed, for the equal and proportionate benefit of all Holders of the Securities or of any series thereof, as follows:

ARTICLE ONE

DEFINITIONS AND OTHER PROVISIONS OF GENERAL APPLICATION

SECTION 101. Definitions.

     For all purposes of this Indenture, except as otherwise expressly provided or unless the context otherwise requires:

               (1) the terms defined in this Article have the meanings assigned to them in this Article and include the plural as well as the singular;

               (2) all other terms used herein which are defined in the Trust Indenture Act, either directly or by reference therein, have the meanings assigned to them therein;

               (3) all accounting terms not otherwise defined herein have the meanings assigned to them in accordance with generally accepted accounting principles, and, except as otherwise herein expressly provided, the term “generally accepted accounting principles” with respect to any computation required or permitted hereunder shall mean such accounting principles as are generally accepted in the United States at the date of such computation;

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               (4) the words “herein”, “hereof” and “hereunder” and other words of similar import refer to this Indenture as a whole and not to any
particular Article, Section or other subdivision; and

               (5) the words “Article” and “Section” refer to an Article and Section, respectively, of this Indenture.

     “Act”, when used with respect to any Holder, has the meaning specified in Section 104.

     “Affiliate” of any specified Person means any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person. For the purposes of this definition, “control” when used with respect to any specified Person means the power to direct the management and policies of such Person, directly or indirectly, whether through the ownership of voting securities, by contract or otherwise; and the terms “controlling” and “controlled” have meanings correlative to the foregoing.

     “Authenticating Agent” means any Person authorized by the Trustee pursuant to Section 614 to act on behalf of the Trustee to authenticate Securities of one or more series.

     “Authorized Newspaper” means a newspaper, in the English language or in an official language of the country of publication, customarily published on each Business Day, whether or not published on Saturdays, Sundays or holidays, and of general circulation in the place in connection with which the term is used or in the financial community of such place.

     “Bankruptcy Law” means Title 11, U.S. Code, or any similar federal or state law for the relief of debtors.

     “Board of Directors” means the board of directors of the Company, or the executive or any other committee of that board duly authorized to act in respect thereof.

     “Board Resolution” means a copy of a resolution certified by the Corporate Secretary or an Assistant Secretary of the Company, the principal financial officer of the Company or any other authorized officer of the Company or a person duly authorized by any of them, to have been duly adopted by the Board of Directors and to be in full force and effect on the date of such certification, and delivered to the Trustee.

     “Business Day”, when used with respect to any Place of Payment or other location, means, except as otherwise provided as contemplated by Section 301 with respect to any series of Securities, each Monday, Tuesday, Wednesday, Thursday and Friday which is not a day on which banking institutions in that Place of Payment or other location are authorized or obligated by law, executive order or regulation to close.

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     “Commission” means the Securities and Exchange Commission, as from time to time constituted, created under the Exchange Act or, if at any time after the execution of this instrument such Commission is not existing and performing the duties now assigned to it under the Trust Indenture Act, then the body performing such duties at such time.

     “Company” means the Person named as the “Company” in the first paragraph of this instrument until a successor Person shall have become such pursuant to the applicable provisions of this Indenture, and thereafter “Company” shall mean such successor Person.

     “Company Request” or “Company Order” means a written request or order signed in the name of the Company by its Chairman of the Board, its Chief Executive Officer, its President, any of its Vice Presidents or any other authorized officer of the Company or a person duly authorized by any of them, and delivered to the Trustee.

     “Consolidated Net Tangible Assets” means, at any date of determination, the total amount of assets after deducting therefrom (i) all current liabilities (excluding (A) any current liabilities that by their terms are extendable or renewable at the option of the obligor thereon to a time more than 12 months after the time as of which the amount thereof is being computed, and (B) current maturities of long-term debt), and (ii) the value (net of any applicable reserves) of all goodwill, trade names, trademarks, patents and other like intangible assets, all as set forth on the consolidated balance sheet of the Company and its consolidated subsidiaries for the Company’s most recently completed fiscal quarter, prepared in accordance with generally accepted accounting principles.

     “Corporate Trust Office” means the office of the Trustee at which at any particular time its corporate trust business shall be principally administered, which at the date hereof is 450 West 33rd Street, New York, NY 10001.

     “corporation” includes corporations, associations, partnerships, limited liability companies, joint-stock companies and business trusts.

     “covenant defeasance” has the meaning specified in Section 1303.

     “Custodian” means any receiver, trustee, assignee, liquidator or similar official under any Bankruptcy Law.

     “Debt” means any obligation created or assumed by any Person for the repayment of money borrowed and any purchase money obligation created or assumed by such Person.

     “Default” means, with respect to a series of Securities, any event which is, or after notice or lapse of time or both would become, an Event of Default with respect to Securities of such series.

     “Defaulted Interest” has the meaning specified in Section 307.

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     “defeasance” has the meaning specified in Section 1302.

     “Definitive Security” means a Security other than a Global Security or a temporary Security.

     “Depositary” means, with respect to Securities of any series issuable in whole or in part in the form of one or more Global Securities, a clearing agency registered under the Exchange Act that is designated to act as Depositary for such Securities as contemplated by Section 301, until a successor Depositary shall have become such pursuant to the applicable provisions of this Indenture, and thereafter shall mean or include each Person which is then a Depositary hereunder, and if at any time there is more than one such Person, shall be a collective reference to such Persons.

     “Dollar” or “$” means the coin or currency of the United States of America as at the time of payment is legal tender for the payment of public and private debts.

     “Event of Default” has the meaning specified in Section 501.

     “Exchange Act” means the Securities Exchange Act of 1934, as amended from time to time, and any statute successor thereto.

     “Funded Debt” means all Debt maturing one year or more from the date of the creation thereof, all Debt directly or indirectly renewable or extendible, at the option of the debtor, by its terms or by the terms of any instrument or agreement relating thereto, to a date one year or more from the date of the creation thereof, and all Debt under a revolving credit or similar agreement obligating the lender or lenders to extend credit over a period of one year or more.

     “Global Security” means a Security in global form that evidences all or part of the Securities of any series and is authenticated and delivered to, and registered in the name of, the Depositary for such Securities or a nominee thereof.

     “Holder” means a Person in whose name a Security is registered in the Security Register.

     “Indenture” means this instrument as originally executed or as it may from time to time be supplemented or amended by one or more indentures supplemental hereto entered into pursuant to the applicable provisions hereof, including, for all purposes of this instrument, and any such supplemental indenture, the provisions of the Trust Indenture Act that are deemed to be a part of and govern this instrument and any such supplemental indenture, respectively. The term “Indenture” also shall include the terms of particular series of Securities established as contemplated by Section 301.

     “interest”, when used with respect to an Original Issue Discount Security which by its terms bears interest only after Maturity, means interest payable after Maturity.

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     “Interest Payment Date”, when used with respect to any Security, means the Stated Maturity of an installment of interest on such Security.

     “Lien” means any mortgage, pledge, security interest, charge, lien or other encumbrance of any kind, whether or not filed, recorded or perfected under applicable law.

     “Maturity”, when used with respect to any Security, means the date on which the principal of such Security or an installment of principal becomes due and payable as therein or herein provided, whether at the Stated Maturity or by declaration of acceleration, call for redemption or otherwise.

     “Notice of Default” means a written notice of the kind specified in Section 501(3).

     “Officer’s Certificate” means a certificate signed by the Chairman of the Board, the Chief Executive Officer, the President, any Vice President or any other authorized officer of the Company or a person duly authorized by any of them, and delivered to the Trustee. The officer signing an Officer’s Certificate given pursuant to Section 1004 shall be the principal executive, financial or accounting officer of the Company.

     “Opinion of Counsel” means a written opinion of legal counsel, who may be an employee of or counsel for the Company and who shall be reasonably acceptable to the Trustee.

     “Original Issue Discount Security” means any Security which provides for an amount less than the stated principal amount thereof to be due and payable upon a declaration of acceleration of the Maturity thereof pursuant to Section 502.

     “Outstanding”, when used with respect to Securities, means, as of the date of determination, all Securities theretofore authenticated and delivered under this Indenture, except:

               (1) Securities theretofore canceled by the Trustee or delivered to the Trustee for cancellation;

               (2) Securities for whose payment or redemption money in the necessary amount has been theretofore deposited with the Trustee or any Paying Agent (other than the Company) in trust or set aside and segregated in trust by the Company (if the Company shall act as its own Paying Agent) for the Holders of such Securities; provided, however, that, if such Securities are to be redeemed, notice of such redemption has been duly given pursuant to this Indenture or provision therefor satisfactory to the Trustee has been made;

               (3) Securities which have been paid pursuant to Section 306 or in exchange for or in lieu of which other Securities have been authenticated and delivered pursuant to this Indenture, other than any such Securities in respect of which there shall have been presented to the Trustee

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proof satisfactory to it that such Securities are held by a bona fide purchaser in whose hands such Securities are valid obligations of the Company; and

               (4) Securities, except to the extent provided in Sections 1302 and 1303, with respect to which the Company has effected defeasance or covenant defeasance as provided in Article Thirteen.

provided, however, that in determining whether the Holders of the requisite principal amount of the Outstanding Securities have given any request, demand, authorization, direction, notice, consent or waiver hereunder, (A) the principal amount of an Original Issue Discount Security that shall be deemed to be Outstanding shall be the amount of the principal thereof that would be due and payable as of the date of such determination upon acceleration of the Maturity thereof on such date pursuant to Section 502, (B) the principal amount of a Security denominated in one or more currencies or currency units other than U.S. dollars shall be the U.S. dollar equivalent of such currencies or currency units, determined in the manner provided as contemplated by Section 301 on the date of original issuance of such Security, of the principal amount (or, in the case of an Original Issue Discount Security, the U.S. dollar equivalent (as so determined) on the date of original issuance of such Security of the amount determined as provided in Clause (A) above) of such Security, and (C) Securities owned by the Company or any other obligor upon the Securities or any Affiliate of the Company or of such other obligor shall be disregarded and deemed not to be outstanding, except that, in determining whether the Trustee shall be protected in relying upon any such request, demand, authorization, direction, notice, consent or waiver, only Securities which the Trustee knows to be so owned shall be so disregarded. Securities so owned as described in Clause (C) above which have been pledged in good faith may be regarded as Outstanding if the pledgee establishes to the satisfaction of the Trustee the pledgee’s right so to act with respect to such Securities and that the pledgee is not the Company or any other obligor upon the Securities or any Affiliate of the Company or of such other obligor.

     “Paying Agent” means any Person authorized by the Company to pay the principal of or any premium or interest on any Securities on behalf of the Company.

     “Periodic Offering” means an offering of Securities of a series from time to time, the specific terms of which Securities, including, without limitation, the rate or rates of interest or formula for determining the rate or rates of interest thereon, if any, the Stated Maturity or Stated Maturities thereof, the original issue date or dates thereof, the redemption provisions, if any, with respect thereto, and any other terms specified as contemplated by Section 301 with respect thereto, are to be determined by the Company upon the issuance of such Securities.

     “Permitted Liens” means (i) Liens upon rights-of-way for pipeline purposes; (ii) any governmental Lien, mechanics’, materialmen’s, carriers’ or similar Lien incurred in the ordinary course of business which is not yet due or which is being contested in good faith by appropriate proceedings and any undetermined Lien which is incidental to construction; (iii) the right reserved to, or vested in, any municipality or public authority by the terms of any right, power, franchise,

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grant, license, permit or by any provision of law, to purchase or recapture or to designate a purchaser of, any property; (iv) Liens of taxes and assessments which are (A) for the then current year, (B) not at the time delinquent, or (C) delinquent but the validity of which is being contested at the time by the Company or any Subsidiary in good faith; (v) Liens of, or to secure performance of, leases; (vi) any Lien upon, or deposits of, any assets in favor of any surety company or clerk of court for the purpose of obtaining indemnity or stay of judicial proceedings; (vii) any Lien upon property or assets acquired or sold by the Company or any Restricted Subsidiary resulting from the exercise of any rights arising out of defaults on receivables; (viii) any Lien incurred in the ordinary course of business in connection with workmen’s compensation, unemployment insurance, temporary disability, social security, retiree health or similar laws or regulations or to secure obligations imposed by statute or governmental regulations; (ix) any Lien upon any property or assets in accordance with customary banking practice to secure any Debt incurred by the Company or any Restricted Subsidiary in connection with the exporting of goods to, or between, or the marketing of goods in, or the importing of goods from, foreign countries; or (x) any Lien in favor of the United States of America or any state thereof, or any other country, or any political subdivision of any of the foregoing, to secure partial, progress, advance, or other payments pursuant to any contract or statute, or any Lien securing industrial development, pollution control, or similar revenue bonds.

     “Person” means any individual, corporation, partnership, joint venture, limited liability company, association, joint-stock company, trust, other entity, unincorporated organization or government or any agency or political subdivision thereof.

     “Place of Payment”, when used with respect to the Securities of any series, means, unless otherwise specifically provided for with respect to such series as contemplated by Section 301, the office or agency of the Company in The City of New York and such other place or places where, subject to the provisions of Section 1002, the principal of and any premium and interest on the Securities of that series are payable as specified as contemplated by Section 301.

     “Predecessor Security” of any particular Security means every previous Security evidencing all or a portion of the same debt as that evidenced by such particular Security; and, for the purposes of this definition, any Security authenticated and delivered under Section 306 in exchange for or in lieu of a mutilated, destroyed, lost or stolen Security shall be deemed to evidence the same debt as the mutilated, destroyed, lost or stolen Security.

     “Principal Property” means (a) any pipeline assets of the Company or any Subsidiary, including any related facilities employed in the transportation, distribution or marketing of natural gas, that is located in the United States or Canada, and (b) any processing or manufacturing plant owned or leased by the Company or any Subsidiary and located within the United States or Canada, except, in the case of either clause (a) or (b), any such assets or plant which, in the opinion of the Board of Directors, is not material in relation to the activities of the Company and its Subsidiaries as a whole.

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     “Redemption Date”, when used with respect to any Security to be redeemed, means the date fixed for such redemption by or pursuant to this Indenture.

     “Redemption Price”, when used with respect to any Security to be redeemed, means the price at which it is to be redeemed pursuant to this Indenture.

     “Regular Record Date” for the interest payable on any Interest Payment Date on the Securities of any series means the date specified for that purpose as contemplated by Section 301.

     “Restricted Subsidiary” means any Subsidiary of the Company owning or leasing any Principal Property.

     “Sale-Leaseback Transaction” means the sale or transfer by the Company or any Restricted Subsidiary of any Principal Property to a Person (other than the Company or a Subsidiary) and the taking back by the Company or any Restricted Subsidiary, as the case may be, of a lease of such Principal Property.

     “Securities” has the meaning stated in the first recital of this Indenture and more particularly means any Securities authenticated and delivered under this Indenture.

     “Security Register” and “Security Registrar” have the respective meanings specified in Section 305.

     “Special Record Date” for the payment of any Defaulted Interest means a date fixed by the Trustee pursuant to Section 307.

     “Stated Maturity”, when used with respect to any Security or any installment of principal thereof or interest thereon, means the date specified in such Security as the fixed date on which the principal of such Security or such installment of principal or interest is due and payable.

     “Subsidiary” means a corporation more than 50% of the outstanding voting stock of which is owned, directly or indirectly, by the Company or by one or more other Subsidiaries, or by the Company and one or more other Subsidiaries. For the purposes of this definition, “voting stock” means stock which ordinarily has voting power for the election of directors, whether at all times or only so long as no senior class of stock has such voting power by reason of any contingency.

     “Trust Indenture Act” means the Trust Indenture Act of 1939 as in force at the date as of which this instrument was executed, except as otherwise provided in Section 905; provided, however, that if the Trust Indenture Act of 1939 is amended after such date, “Trust Indenture Act” means, to the extent required by any such amendment, the Trust Indenture Act of 1939 as so amended.

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     “Trustee” means the Person named as the “Trustee” in the first paragraph of this instrument until a successor Trustee shall have become such pursuant to the applicable provisions of this Indenture, and thereafter “Trustee” shall mean or include each Person who is then a Trustee hereunder, and if at any time there is more than one such Person, “Trustee” as used with respect to the Securities of any series shall mean each Trustee with respect to Securities of that series.

     “U.S. Government Obligations” means securities which are (i) direct obligations of the United States for the payment of which its full faith and credit is pledged, or (ii) obligations of a Person controlled or supervised by and acting as an agency or instrumentality of the United States, the payment of which is unconditionally guaranteed as a full faith and credit obligation by the United States, each of which are not callable or redeemable at the option of the issuer thereof.

     “Vice President”, when used with respect to the Company or Trustee, means any vice president, whether or not designated by a number or a word or words added before or after the title “vice president”.

SECTION 102. Compliance Certificates and Opinions.

     Upon any application or request by the Company to the Trustee to take any action under any provision of this Indenture, the Company shall furnish to the Trustee such certificates or opinions as may be required under the Trust Indenture Act. Each such certificate or opinion shall be given in the form of an Officer’s Certificate, if to be given by an officer of the Company, or an Opinion of Counsel, if to be given by counsel, and shall comply with the requirements of the Trust Indenture Act and any other requirements set forth in this Indenture.

     Every certificate or opinion with respect to compliance with a condition or covenant provided for in this Indenture (except for certificates provided for in Section 1004) shall include:

               (1) a statement that each individual signing such certificate or opinion has read such covenant or condition and the definitions herein relating thereto;

               (2) a brief statement as to the nature and scope of the examination or investigation upon which the statements or opinions contained in such certificate or opinion are based;

               (3) a statement that, in the opinion of each such individual, he has made such examination or investigation as is necessary to enable him to express an informed opinion as to whether or not such covenant or condition has been complied with; and

               (4) a statement as to whether, in the opinion of each such individual, such condition or covenant has been complied with.

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SECTION 103. Form Of Documents Delivered To Trustee.

     In any case where several matters are required to be certified by, or covered by an opinion of, any specified Person, it is not necessary that all such matters be certified by, or covered by the opinion of, only one such Person, or that they be so certified or covered by only one document, but one such Person may certify or give an opinion with respect to some matters and one or more other such Persons as to other matters, and any such Person may certify or give an opinion as to such matters in one or several documents.

     Any certificate or opinion of an officer of the Company may be based, insofar as it relates to legal matters, upon a certificate or opinion of, or representations by, counsel, unless such officer knows, or in the exercise of reasonable care should know, that the certificate or opinion or representations with respect to the matters upon which his certificate or opinion is based are erroneous. Any such certificate or opinion of counsel may be based, insofar as it relates to factual matters, upon a certificate or opinion of, or representations by, an officer or officers of the Company stating that the information with respect to such factual matters is in the possession of the Company, unless such counsel knows, or in the exercise of reasonable care should know, that the certificate or opinion or representations with respect to such matters are erroneous.

     Where any Person is required to make, give or execute two or more applications, requests, consents, certificates, statements, opinions or other instruments under this Indenture, they may, but need not, be consolidated and form one instrument.

SECTION 104. Acts Of Holders; Record Dates.

     Any request, demand, authorization, direction, notice, consent, waiver or other action provided or permitted by this Indenture to be given or taken by Holders may be embodied in and evidenced by one or more instruments of substantially similar tenor signed (either physically or by means of a facsimile or an electronic transmission, provided that such electronic transmission is transmitted through the facilities of a Depositary) by such Holders in person or by agent duly appointed in writing; and, except as herein otherwise expressly provided, such action shall become effective when such instrument or instruments are delivered (either physically or by means of a facsimile or an electronic transmission, provided that such electronic transmission is transmitted through the facilities of a Depositary) to the Trustee and, where it is hereby expressly required, to the Company. Such instrument or instruments (and the action embodied therein and evidenced thereby) are herein sometimes referred to as the “Act” of the Holders signing such instrument or instruments. Proof of execution of any such instrument or of a writing appointing any such agent shall be sufficient for any purpose of this Indenture and (subject to Section 315 of the Trust Indenture Act) conclusive in favor of the Trustee and the Company, if made in the manner provided in this Section.

     The fact and date of the execution by any Person of any such instrument or writing may be proved by the affidavit of a witness of such
execution or by a certificate of a notary public or other

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officer authorized by law to take acknowledgments of deeds, certifying that the individual signing such instrument or writing acknowledged to him the execution thereof. Where such execution is by a signer acting in a capacity other than his individual capacity, such certificate or affidavit shall also constitute sufficient proof of his authority. The fact and date of the execution of any such instrument or writing, or the authority of the Person executing the same, may also be proved in any other manner which the Trustee deems sufficient.

     The ownership, principal amount and serial numbers of Securities held by any Person, and the date of commencement of such Person’s holding the same, shall be proved by the Security Register.

     Any request, demand, authorization, direction, notice, consent, waiver or other action of the Holder of any Security shall bind every future Holder of the same Security and the Holder of every Security issued upon the registration of transfer thereof or in exchange therefor or in lieu thereof in respect of anything done, omitted or suffered to be done by the Trustee or the Company in reliance thereon, whether or not notation of such action is made upon such Security.

     Without limiting the foregoing, a Holder entitled hereunder to give or take any action hereunder with regard to any particular Security may do so with regard to all or any part of the principal amount of such Security or by one or more duly appointed agents each of which may do so pursuant to such appointment with regard to all or any different part of such principal amount.

     The Company may set any day as the record date for the purpose of determining the Holders of Outstanding Securities of any series entitled to give or take any request, demand, authorization, direction, notice, consent, waiver or other action provided or permitted by this Indenture to be given or taken by Holders of Securities of such series, but the Company shall have no obligation to do so. With regard to any record date set pursuant to this paragraph, the Holders of Outstanding Securities of the relevant series on such record date (or their duly appointed agents), and only such Persons, shall be entitled to give or take the relevant action, whether or not such Holders remain Holders after such record date.

SECTION 105. Notices, Etc., To Trustee And Company.

     Any request, demand, authorization, direction, notice, consent, waiver or Act of Holders or other document provided or permitted by this Indenture to be made upon, given or furnished to, or filed with,

               (1) the Trustee by any Holder or by the Company shall be sufficient for every purpose hereunder if made, given, furnished or filed in writing to or with the Trustee at its Corporate Trust Office, Attention: Capital Trust Fiduciary Services, or

               (2) the Company by the Trustee or by any Holder shall be sufficient for every purpose hereunder (unless otherwise herein expressly provided) if in writing and mailed, first-class

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postage prepaid, to the Company addressed to it at 1001 Louisiana Street, Houston, Texas 77002, to the attention of the Corporate Secretary, or at any other address previously furnished in writing to the Trustee by the Company.

SECTION 106. Notice To Holders; Waiver.

     Where this Indenture provides for notice to Holders of any event, such notice shall be sufficiently given (unless otherwise herein expressly provided) if in writing and mailed, first-class postage prepaid (if international mail, by air mail), to each Holder affected by such event, at his address as it appears in the Security Register, not later than the latest date (if any), and not earlier than the earliest date (if any), prescribed for the giving of such notice. In any case where notice to Holders is given by mail, neither the failure to mail such notice, nor any defect in any notice so mailed, to any particular Holder shall affect the sufficiency of such notice with respect to other Holders. Any notice mailed to a Holder in the manner herein prescribed shall be conclusively deemed to have been received by such Holder, whether or not such Holder actually receives such notice.

     Where this Indenture provides for notice in any manner, such notice may be waived in writing by the Person entitled to receive such notice, either before or after the event, and such waiver shall be the equivalent of such notice. Waivers of notice by Holders shall be filed with the Trustee, but such filing shall not be a condition precedent to the validity of any action taken in reliance upon such waiver.

     In case by reason of the suspension of regular mail service or by reason of any other cause it shall be impracticable to give such notice by mail, then such notification as shall be made with the approval of the Trustee shall constitute a sufficient notification for every purpose hereunder.

SECTION 107. Conflict With Trust Indenture Act.

     If any provision hereof limits, qualifies or conflicts with a provision of the Trust Indenture Act that is required under such Act to be a part of and govern this Indenture, the latter provision shall control. If any provision of this Indenture modifies or excludes any provision of the Trust Indenture Act that may be so modified or excluded, the latter provision shall be deemed to apply to this Indenture as so modified or excluded, as the case may be.

SECTION 108. Effect Of Headings And Table Of Contents.

     The Article and Section headings herein and the Table of Contents are for convenience only and shall not affect the construction hereof.

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SECTION 109. SUCCESSORS AND ASSIGNS.

     All covenants and agreements in this Indenture by the Company shall bind its successors and assigns, whether so expressed or not.

SECTION 110. SEPARABILITY CLAUSE.

     In case any provision in this Indenture or in the Securities shall be invalid, illegal or unenforceable, the validity, legality and enforceability of the remaining provisions shall not in any way be affected or impaired thereby.

SECTION 111. BENEFITS OF INDENTURE.

     Nothing in this Indenture or in the Securities, express or implied, shall give to any Person, other than the parties hereto and their successors hereunder and the Holders, any benefit or any legal or equitable right, remedy or claim under this Indenture.

SECTION 112. GOVERNING LAW.

     This Indenture and the Securities shall be governed by and construed in accordance with the law of the State of New York.

SECTION 113. LEGAL HOLIDAYS.

     In any case where any Interest Payment Date, Redemption Date or Stated Maturity of any Security shall not be a Business Day at any Place of Payment, then (notwithstanding any other provision of this Indenture or of the Securities (other than a provision of the Securities of any series which specifically states that such provision shall apply in lieu of this Section)) payment of interest or principal (and premium, if any) need not be made at such Place of Payment on such date, but may be made on the next succeeding Business Day at such Place of Payment with the same force and effect as if made on the Interest Payment Date or Redemption Date, or at the Stated Maturity, provided that no interest shall accrue for the period from and after such Interest Payment Date, Redemption Date or Stated Maturity, as the case may be.

SECTION 114. LANGUAGE OF NOTICES, ETC.

     Any request, demand, authorization, direction, notice, consent, waiver or Act required or permitted under this Indenture shall be in the English language, except that any published notice may be in an official language of the country of publication.

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SECTION 115. INCORPORATORS, STOCKHOLDERS, OFFICERS AND DIRECTORS OF THE COMPANY
EXEMPT FROM INDIVIDUAL LIABILITY.

     No recourse under or upon any obligation, covenant or agreement of or contained in this Indenture or of or contained in any Security, or for any claim based thereon or otherwise in respect thereof, or in any Security, or because of the creation of any indebtedness represented thereby, shall be had against any incorporator, stockholder, officer or director, as such, past, present or future, of the Company or any successor Person, either directly or through the Company or any successor Person, whether by virtue of any constitution, statute or rule of law, or by the enforcement of any assessment or penalty or otherwise; it being expressly understood that all such liability is hereby expressly waived and released as a condition of, and as a part of the consideration for, the execution of this Indenture and the issue of the Securities.

ARTICLE TWO

SECURITY FORMS

SECTION 201. FORMS GENERALLY.

     The Securities of each series shall be in substantially the form set forth in this Article, or in such other form as shall be established by or pursuant to a Board Resolution or in one or more indentures supplemental hereto, in each case with such appropriate insertions, omissions, substitutions and other variations as are required or permitted by this Indenture, and may have such letters, numbers or other marks of identification and such legends or endorsements placed thereon as may be required to comply with the rules of any securities exchange or as may, consistently herewith, be determined by the officers executing such Securities, as evidenced by their execution of the Securities.

     The definitive Securities shall be printed, lithographed or engraved on steel engraved borders or may be produced in any other manner, all as determined by the officers executing such Securities, as evidenced by their execution of such Securities. If the form of Securities of any series is established by action taken pursuant to a Board Resolution, a copy of an appropriate record of such action shall be certified by an authorized officer or other authorized person on behalf of the Company and delivered to the Trustee at or prior to the delivery of the Company Order contemplated by Section 303 for the authentication and delivery of such Securities.

SECTION 202. FORM OF FACE OF SECURITY.

     [Insert any legend required by the United States Internal Revenue Code and the regulations thereunder.]

     [If a Global Security, — insert legend required by Section 204 of the Indenture] [If applicable, insert—UNLESS THIS SECURITY IS PRESENTED BY AN AUTHORIZED REPRESENTATIVE

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OF THE DEPOSITORY TRUST COMPANY, A NEW YORK CORPORATION, TO THE COMPANY OR ITS AGENT FOR REGISTRATION OF TRANSFER, EXCHANGE OR PAYMENT, AND ANY SECURITY ISSUED IS REGISTERED IN THE NAME OF CEDE & CO. OR SUCH OTHER NAME AS IS REQUESTED BY AN AUTHORIZED REPRESENTATIVE OF THE DEPOSITORY TRUST COMPANY (AND ANY PAYMENT IS MADE TO CEDE & CO. OR TO SUCH OTHER ENTITY AS IS REQUESTED BY AN AUTHORIZED REPRESENTATIVE OF THE DEPOSITORY TRUST COMPANY), ANY TRANSFER, PLEDGE OR OTHER USE HEREOF FOR VALUE OR OTHERWISE BY OR TO ANY PERSON IS WRONGFUL SINCE THE REGISTERED OWNER HEREOF, CEDE & CO., HAS AN INTEREST HEREIN.]

EL PASO ENERGY CORPORATION

[TITLE OF SECURITY]

NO. U.S.$

[CUSIP NO. ]

     EL PASO ENERGY CORPORATION, a corporation duly incorporated and existing under the laws of Delaware (herein called the “Company”, which term includes any successor Person under the Indenture hereinafter referred to), for value received, hereby promises to pay to      , or registered assigns, the principal sum of            United States Dollars on

                         [if the Security is to bear interest prior to Maturity, insert —, and to pay interest thereon from      , or from the most recent Interest Payment Date to which interest has been paid or duly provided for,           semi-annually on            and            in each year, commencing      , at the rate of      % per annum, until the principal hereof is paid or made available for payment [if applicable, insert—, and at the rate of      % per annum on any overdue principal and premium and on any overdue installment of interest]. The interest so payable, and punctually paid or duly provided for, on any Interest Payment Date will, as provided in such Indenture, be paid to the Person in whose name this Security (or one or more Predecessor Securities) is registered at the close of business on the Regular Record Date for such interest, which shall be the

                         or (whether or not a Business Day), as the case may be, next preceding such Interest Payment Date. Any such interest not so punctually paid or duly provided for will forthwith cease to be payable to the Holder on such Regular Record Date and may either be paid to the Person in whose name this Security (or one or more Predecessor Securities) is registered at the close of business on a Special Record Date for the payment of such Defaulted Interest to be fixed by the Trustee, notice of which shall be given to Holders of Securities of this series not less than 10 days prior to such Special Record Date, or be paid at any time in any other lawful manner not inconsistent with the requirements of any securities exchange on which the Securities of this series may be listed, and upon such notice as may be required by such exchange, all as more fully provided in such Indenture].

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     [If the Security is not to bear interest prior to Maturity, insert—The principal of this Security shall not bear interest except in the case of a default in payment of principal upon acceleration, upon redemption or at Stated Maturity and in such case the overdue principal of this Security shall bear interest at the rate of % per annum, which shall accrue from the date of such default in payment to the date payment of such principal has been made or duly provided for. Interest on any overdue principal shall be payable on demand. Any such interest on any overdue principal that is not so paid on demand shall bear interest at the rate of      % per annum, which shall accrue from the date of such demand for payment to the date payment of such interest has been made or duly provided for, and such interest shall also be payable on demand.]

     [If a Global Security, insert—Payment of the principal of [(and premium, if any)] and [if applicable, insert—any such] interest on this Security will be made by transfer of immediately available funds to a bank account in

     designated by the Holder in such coin or currency of the United States of America as at the time of payment is legal tender for payment of public and private debts [state other currency].]

     [If a Definitive Security insert—Payment of the principal of [(and premium, if any)] and [if applicable, insert—any such] interest on this Security will be made at the office or agency of the Company maintained for that purpose in         , [in such coin or currency of the United States of America as at the time of payment is legal tender for payment of public and private debts] [state other currency] [or subject to any laws or regulations applicable thereto and to the right of the Company (as provided in the Indenture) to rescind the designation of any such Paying Agent, at the [main] offices of            in            and            in      , or at such other offices or agencies as the Company may designate, by [United States Dollar] [state other currency] check drawn on, or transfer to a [United States Dollar] account maintained by the payee with, a bank in The City of New York [   ] (so long as the applicable Paying Agent has received proper transfer instructions in writing at least [   ] days prior to the payment date)] [if applicable, insert—; provided, however, that payment of interest may be made at the option of the Company by [United States Dollar] [state other currency] check mailed to the addresses of the Persons entitled thereto as such addresses shall appear in the Security Register] [or by transfer to a [United States Dollar] [state other currency] account maintained by the payee with a bank in The City of New York [state other Place of Payment] (so long as the applicable Paying Agent has received proper transfer instructions in writing by the Record Date prior to the applicable Interest Payment Date)].]

     Reference is hereby made to the further provisions of this Security set forth on the reverse hereof, which further provisions shall for all
purposes have the same effect as if set forth at this place.

     Unless the certificate of authentication hereon has been executed by the Trustee referred to on the reverse hereof by manual signature, this Security shall not be entitled to any benefit under the Indenture or be valid or obligatory for any purpose.

     IN WITNESS WHEREOF, the Company has caused this instrument to be duly executed.

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Dated:	EL PASO ENERGY CORPORATION
	By:
	Name:
	Title:

SECTION 203. FORM OF REVERSE OF SECURITY.

     This Security is one of a duly authorized issue of securities of the Company (the “Securities”), issued and to be issued in one or more series under an Indenture dated as of                                          (the “Indenture”), between the Company and The Chase Manhattan Bank, as Trustee (the “Trustee”, which term includes any successor trustee under the Indenture), to which Indenture and all indentures supplemental thereto reference is hereby made for a statement of the respective rights, limitations of rights, obligations, duties and immunities thereunder of the Company, the Trustee and the Holders of the Securities and of the terms upon which the Securities are, and are to be, authenticated and delivered. As provided in the Indenture, the Securities may be issued in one or more series, which different series may be issued in various aggregate principal amounts, may mature at different times, may bear interest, if any, at different rates, may be subject to different redemption provisions, if any, may be subject to different sinking, purchase or analogous funds, if any, may be subject to different covenants and Events of Default and may otherwise vary as in the Indenture provided or permitted. This Security is one of the series designated on the face hereof [if applicable, insert—, limited in aggregate principal amount to U.S.$      ].

[If applicable, insert—The Securities of this series are subject to redemption upon not less than 30 nor more than 60 days’ notice by mail, [if applicable, insert—(1) on                                          in any year commencing with the year            and ending with the year            through operation of the sinking fund for this series at a Redemption Price equal to 100% of the principal amount, and (2)] at any time [if applicable, insert—on or after      ,      ], as a whole or in part, at the election of the Company, at the following Redemption Prices (expressed as percentages of the principal amount): If redeemed (if applicable, insert—on or before      ,      %, and if redeemed] during the 12-month period beginning           of the years indicated,

YEAR REDEMPTION PRICE YEAR REDEMPTION PRICE

and thereafter at a Redemption Price equal to      % of the principal amount, together in the case of any such redemption [if applicable, insert—(whether through operation of the sinking fund or otherwise)] with accrued interest to the Redemption Date, but interest installments whose Stated Maturity is on or prior to such Redemption Date will be payable to the Holders of such Securities,

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or one or more Predecessor Securities, of record at the close of business on the relevant Record Dates referred to on the face hereof, all as provided in the Indenture.]

     [If applicable, insert—The Securities of this series are subject to redemption upon not less than 30 nor more than 60 days’ notice by mail, (1) on            in any year commencing with the year            and ending with the year            through operation of the sinking fund for this series at the Redemption Prices for redemption through operation of the sinking fund (expressed as percentages of the principal amount) set forth in the table below, and (2) at any time [if applicable, insert—on or after     ], as a whole or in part, at the election of the Company, at the Redemption Prices for redemption otherwise than through operation of the sinking fund (expressed as percentages of the principal amount) set forth in the table below: If redeemed during the 12-month period beginning            of the years indicated,

	REDEMPTION PRICE	REDEMPTION PRICE FOR
	FOR REDEMPTION	REDEMPTION OTHERWISE THAN THROUGH
	THROUGH OPERATION	OPERATION
YEAR	OF THE SINKING FUND	OF THE SINKING FUND

and thereafter at a Redemption Price equal to      % of the principal amount, together in the case of any such redemption (whether through operation of the sinking fund or otherwise) with accrued interest to the Redemption Date, but interest installments whose Stated Maturity is on or prior to such Redemption Date will be payable to the Holders of such Securities, or one or more Predecessor Securities, of record at the close of business on the relevant Record Dates referred to on the face hereof, all as provided in the Indenture.]

     [If applicable, insert—The sinking fund for this series provides for the redemption on            in each year beginning with the year            and ending with the year            of [if applicable,—not less than $      (“mandatory sinking fund”) and not more than] $        aggregate principal amount of Securities of this series. Securities of this series acquired or redeemed by the Company otherwise than through [if applicable,—mandatory] sinking fund payments may be credited against subsequent [if applicable,—mandatory] sinking fund payments otherwise required to be made [if applicable,—in the inverse order in which they become due].]

     [If the Security is subject to redemption in part of any kind, insert—In the event of redemption of this Security in part only, a new Security or Securities of this series and of like tenor for the unredeemed portion hereof will be issued in the name of the Holder hereof upon the cancellation hereof.]

     [If applicable, insert—The Securities of this series are not redeemable prior to Stated Maturity.]

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     [If the Security is not an Original Issue Discount Security, insert—If an Event of Default with respect to Securities of this series shall occur and be continuing, the principal of the Securities of this series may be declared due and payable in the manner and with the effect provided in the Indenture.]

     [If the Security is an Original Issue Discount Security, insert—If an Event of Default with respect to Securities of this series shall occur and be continuing, an amount of principal of the Securities of this series may be declared due and payable in the manner and with the effect provided in the Indenture. Such amount shall be equal to—insert formula for determining the amount. Upon payment (i) of the amount of principal so declared due and payable, and (ii) of interest on any overdue principal and overdue interest, all of the Company’s obligations in respect of the payment of the principal of and interest, if any, on the Securities of this series shall terminate.)

     The Indenture permits, with certain exceptions as therein provided, the amendment thereof and the modification of the rights and obligations of the Company and the rights of the Holders of the Securities of each series to be affected under the Indenture at any time by the Company and the Trustee with the consent of the Holders of a majority in aggregate principal amount of the Outstanding Securities of all series to be affected (voting as one class). The Indenture also contains provisions permitting the Holders of a majority in aggregate principal amount of the Outstanding Securities of all affected series (voting as one class), on behalf of the Holders of all Securities of such series, to waive compliance by the Company with certain provisions of the Indenture. The Indenture permits, with certain exceptions as therein provided, the Holders of a majority in principal amount of Securities of any series then Outstanding to waive past defaults under the Indenture with respect to such series and their consequences. Any such consent or waiver by the Holder of this Security shall be conclusive and binding upon such Holder and upon all future Holders of this Security and of any Security issued upon the registration of transfer hereof or in exchange herefor or in lieu hereof, whether or not notation of such consent or waiver is made upon this Security.

     As provided in and subject to the provisions of the Indenture, the Holder of this Security shall not have the right to institute any proceeding with respect to the Indenture or for the appointment of a receiver or trustee or for any other remedy thereunder, unless such Holder shall have previously given the Trustee written notice of a continuing Event of Default with respect to the Securities of this series, the Holders of not less than 25% in principal amount of the Securities of this series at the time Outstanding shall have made written request to the Trustee to institute proceedings in respect of such Event of Default as Trustee and offered the Trustee reasonable indemnity and the Trustee shall not have received from the Holders of a majority in principal amount of Securities of this series at the time Outstanding a direction inconsistent with such request, and shall have failed to institute any such proceeding, for 60 days after receipt of such notice, request and offer of indemnity. The foregoing shall not apply to any suit instituted by the Holder of this Security for the enforcement of any payment of principal hereof or [any premium or] interest hereon on or after the respective due dates expressed herein.

     No reference herein to the Indenture and no provision of this Security or of the Indenture shall alter or impair the obligation of the Company, which is absolute and unconditional, to pay the

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principal of and [any premium and] interest on this Security at the times, place(s) and rate, and in the coin or currency, herein prescribed.

     [If a Global Security, insert—This Global Security or portion hereof may not be exchanged for Definitive Securities of this series except in the limited circumstances provided in the Indenture.

     The holders of beneficial interests in this Global Security will not be entitled to receive physical delivery of Definitive Securities except as described in the Indenture and will not be considered the Holders thereof for any purpose under the Indenture.]

     [If a Definitive Security, insert—As provided in the Indenture and subject to certain limitations therein set forth, the transfer of this Security is registerable in the Security Register, upon surrender of this Security for registration of transfer at the office or agency of the Company in [if applicable, insert — any place where the principal of and any premium and interest on this Security are payable] [if applicable, insert— The City of New York [, or, subject to any laws or regulations applicable thereto and to the right of the Company (limited as provided in the Indenture) to rescind the designation of any such transfer agent, at the [main] offices of

in and in

or at such other offices or agencies as the Company may designate]], duly endorsed by, or accompanied by a written instrument of transfer in form satisfactory to the Company and the Security Registrar duly executed by, the Holder hereof or his attorney duly authorized in writing, and thereupon one or more new Securities of this series and of like tenor, of authorized denominations and for the same aggregate principal amount, will be issued to the designated transferee or transferees.]

     The Securities of this series are issuable only in registered form without coupons in denominations of U.S.$                     and any integral multiple thereof. As provided in the Indenture and subject to certain limitations therein set forth, Securities of this series are exchangeable for a like aggregate principal amount of Securities of this series and of like tenor of a different authorized denomination, as requested by the Holder surrendering the same.

     No service charge shall be made for any such registration of transfer or exchange, but the Company may require payment of a sum sufficient to cover any tax or other governmental charge payable in connection therewith.

     Prior to due presentment of this Security for registration of transfer, the Company, the Trustee and any agent of the Company or the Trustee may treat the Person in whose name this Security is registered as the owner hereof for all purposes, whether or not this Security be overdue, and neither the Company, the Trustee nor any such agent shall be affected by notice to the contrary.

     No recourse under or upon any obligation, covenant or agreement of or contained in the Indenture or of or contained in any Security, or for any claim based thereon or otherwise in respect thereof, or in any Security, or because of the creation of any indebtedness represented thereby, shall be had against any incorporator, stockholder, officer or director, as such, past, present or future, of

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the Company or of any successor Person, either directly or through the Company or any successor Person, whether by virtue of any constitution, statute or rule of law, or by the enforcement of any assessment, penalty or otherwise; it being expressly understood that all such liability is hereby expressly waived and released by the acceptance hereof and as a condition of, and as part of the consideration for, the Securities and the execution of the Indenture.

     The Indenture provides that the Company (a) will be discharged from any and all obligations in respect of the Securities (except for certain obligations described in the Indenture), or (b) need not comply with certain restrictive covenants of the Indenture, in each case if the Company deposits, in trust, with the Trustee money or U.S. Government Obligations (or a combination thereof) which through the payment of interest thereon and principal thereof in accordance with their terms will provide money, in an amount sufficient to pay all the principal of and interest on the Securities, but such money need not be segregated from other funds except to the extent required by law.

     This Security shall be governed by and construed in accordance with the laws of the State of New York.

     All terms used in this Security which are defined in the Indenture shall have the meanings assigned to them in the Indenture.

     [If a Definitive Security, insert as a separate page—

     FOR VALUE RECEIVED, the undersigned hereby sell(s), assign(s) and transfer(s) unto

(Please Print or Typewrite Name and Address of Assignee)

the within instrument of EL PASO ENERGY CORPORATION and does hereby irrevocably constitute and appoint                             Attorney to transfer said instrument on the books of the within-named Company, with full power of substitution in the premises.

Please Insert Social Security or
Other Identifying Number of Assignee:

Dated:
	(Signature)

NOTICE: The signature to this assignment must correspond with the name as written upon the face of the within instrument in every particular, without alteration or enlargement or any change whatever.]

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SECTION 204. GLOBAL SECURITIES.

     Every Global Security authenticated and delivered hereunder shall bear a legend in substantially the following form:

     THIS SECURITY IS A GLOBAL SECURITY WITHIN THE MEANING OF THE INDENTURE HEREINAFTER REFERRED TO AND IS REGISTERED IN THE NAME OF A DEPOSITARY OR A NOMINEE THEREOF. THIS SECURITY MAY NOT BE TRANSFERRED TO, OR REGISTERED OR EXCHANGED FOR SECURITIES REGISTERED IN THE NAME OF, ANY PERSON OTHER THAN THE DEPOSITARY OR A NOMINEE THEREOF AND NO SUCH TRANSFER MAY BE REGISTERED, EXCEPT IN THE LIMITED CIRCUMSTANCES DESCRIBED IN THE INDENTURE. EVERY SECURITY AUTHENTICATED AND DELIVERED UPON REGISTRATION OF TRANSFER OF, OR IN EXCHANGE FOR OR IN LIEU OF, THIS SECURITY SHALL BE A GLOBAL SECURITY SUBJECT TO THE FOREGOING, EXCEPT IN SUCH LIMITED CIRCUMSTANCES.

     If Securities of a series are issuable in whole or in part in the form of one or more Global Securities, as specified as contemplated by Section 301, then, notwithstanding Clause (9) of Section 301 and the provisions of Section 302, any Global Security shall represent such of the Outstanding Securities of such series as shall be specified therein and may provide that it shall represent the aggregate amount of Outstanding Securities from time to time endorsed thereon and that the aggregate amount of Outstanding Securities represented thereby may from time to time be reduced or increased, as the case may be, to reflect exchanges. Any endorsement of a Global Security to reflect the amount, or any reduction or increase in the amount, of Outstanding Securities represented thereby shall be made in such manner and upon instructions given by such Person or Persons as shall be specified therein or in a Company Order. Subject to the provisions of Sections 303, 304 and 305, the Trustee shall deliver and redeliver any Global Security in the manner and upon instructions given by the Person or Persons specified therein or in the applicable Company Order. Any instructions by the Company with respect to endorsement or delivery or redelivery of a Global Security shall be in a Company Order (which need not comply with Section 102 and need not be accompanied by an Opinion of Counsel).

     The provisions of the last sentence of Section 303 shall apply to any Security represented by a Global Security if such Security was never issued and sold by the Company and the Company delivers to the Trustee the Global Security together with a Company Order (which need not comply with Section 102 and need not be accompanied by an Opinion of Counsel) with regard to the reduction or increase, as the case may be, in the principal amount of Securities represented thereby, together with the written statement contemplated by the last sentence of Section 303.

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SECTION 205. FORM OF TRUSTEES CERTIFICATE OF AUTHENTICATION.

     The Trustee’s certificates of authentication shall be in substantially the following form:

     This is one of the Securities of the series designated therein referred to in the within-mentioned Indenture.

THE CHASE MANHATTAN BANK,
As Trustee
By:
	Authorized Officer

ARTICLE THREE

THE SECURITIES

SECTION 301. AMOUNT UNLIMITED; ISSUABLE IN SERIES.

     The aggregate principal amount of Securities which may be authenticated and delivered under this Indenture is unlimited.

     The Securities may be issued in one or more series. There shall be established in or pursuant to a Board Resolution and, subject to Section 303, set forth, or determined in the manner provided, in an Officer’s Certificate, or established in one or more indentures supplemental hereto, prior to the issuance of Securities of any series,

               (1) the title of the Securities of the series (which shall distinguish the Securities of the series from Securities of any other series);

               (2) any limit upon the aggregate principal amount of the Securities of the series which may be authenticated and delivered under this Indenture (except for Securities authenticated and delivered upon registration of transfer of, or in exchange for, or in lieu of, other Securities of the series pursuant to Section 304, 305, 306, 906 or 1107 and except for any Securities which, pursuant to Section 303, are deemed never to have been authenticated and delivered hereunder);

               (3) the Person to whom any interest on a Security of the series shall be payable, if other than the Person in whose name that Security (or one or more Predecessor Securities) is registered at the close of business on the Regular Record Date for such interest;

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               (4) the date or dates on which the principal of the Securities of the series is payable or the method of determination thereof;

               (5) the rate or rates at which the Securities of the series shall bear interest, if any, or the method of determination thereof, the date or dates from which such interest shall accrue, or the method of determination thereof, the Interest Payment Dates on which any such interest shall be payable and the Regular Record Date for any interest payable on any Interest Payment Date;

               (6) the place or places where, subject to the provisions of Section 1002, the principal of and any premium and interest on Securities of the series shall be payable, Securities of the series may be surrendered for registration of transfer, Securities of the series may be surrendered for exchange and notices, and demands to or upon the Company in respect of the Securities of the series and this Indenture may be served;

               (7) the period or periods within which, the price or prices at which and the terms and conditions upon which Securities of the series may be redeemed, in whole or in part, at the option of the Company;

               (8) the obligation, if any, of the Company to redeem or purchase Securities of the series pursuant to any sinking fund or analogous provisions or upon the happening of a specified event or at the option of a Holder thereof and the period or periods within which, the price or prices at which and the terms and conditions upon which Securities of the series shall be redeemed or purchased, in whole or in part, pursuant to such obligation;

               (9) if other than denominations of $1,000 and any integral multiple thereof, the denominations in which Securities of the series shall be issuable;

               (10) whether payment of principal of and premium, if any, and interest, if any, on the Securities of the series shall be without deduction for taxes, assessments or governmental charges paid by Holders of the series;

               (11) the currency, currencies or currency units in which payment of the principal of and any premium and interest on any Securities of the series shall be payable if other than the currency of the United States of America and the manner of determining the equivalent thereof in the currency of the United States of America for purposes of the definition of “Outstanding” in Section 101;

               (12) if the amount of payments of principal of or any premium or interest on any Securities of the series may be determined with reference to an index, the manner in which such amounts shall be determined;

               (13) if the principal of or any premium or interest on any Securities of the series is to be payable, at the election of the Company or a Holder thereof, in one or more currencies or

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currency units other than that or those in which the Securities are stated to be payable, the currency, currencies or currency units in which payment of the principal of and any premium and interest on Securities of such series as to which such election is made shall be payable, and the periods within which and the terms and conditions upon which such election is to be made;

               (14) if other than the principal amount thereof, the portion of the principal amount of Securities of the series which shall be payable upon declaration of acceleration of the Maturity thereof pursuant to Section 502 or the method of determination thereof;

               (15) if and as applicable, that the Securities of the series shall be issuable in whole or in part in the form of one or more Global Securities and, in such case, the Depositary or Depositaries for such Global Security or Global Securities and any circumstances other than those set forth in Section 305 in which any such Global Security may be transferred to, and registered and exchanged for Securities registered in the name of, a Person other than the Depositary for such Global Security or a nominee thereof and in which any such transfer may be registered;

               (16) any deletions from, modifications of or additions to the Events of Default set forth in Section 501 or the covenants of the Company set forth in Article Ten pertaining to the Securities of the series;

               (17) if other than as provided in Sections 1302 and 1303, the means of defeasance or covenant defeasance as may be specified for the Securities of the series;

               (18) if other than the Trustee, the identity of the Security Registrar and any Paying Agent; and

               (19) any other terms of the series (which terms shall not be inconsistent with the provisions of this Indenture, except as permitted by Section 901(4)).

     All Securities of any one series shall be substantially identical except as to denomination and except as may otherwise be provided in or pursuant to the Board Resolution referred to above and (subject to Section 303) set forth, or determined in the manner provided, in the Officer’s Certificate referred to above or in any such indenture supplemental hereto.

     All Securities of any one series need not be issued at the same time and, unless otherwise provided, a series may be reopened, without the consent of the Holders, for increases in the aggregate principal amount of such series of Securities and issuances of additional Securities of such series or for the establishment of additional terms with respect to the Securities of such series.

     If any of the terms of the series are established by action taken by or pursuant to a Board Resolution, a copy of an appropriate record of such action shall be certified by an authorized officer or other authorized person on behalf of the Company and delivered to the Trustee at or prior to the

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delivery of the Officer’s Certificate setting forth, or providing the manner for determining, the terms of the series.

     With respect to Securities of a series subject to a Periodic Offering, such Board Resolution or Officer’s Certificate may provide general terms for Securities of such series and provide either that the specific terms of particular Securities of such series shall be specified in a Company Order or that such terms shall be determined by the Company, or one or more of the Company’s agents designated in an Officer’s Certificate, in accordance with a Company Order.

SECTION 302. DENOMINATIONS.

     The Securities of each series shall be issuable only in registered form without coupons in such denominations as shall be specified as contemplated by Section 301. In the absence of any such specified denomination with respect to the Securities of any series, the Securities of such series shall be issuable in denominations of $1,000 and any integral multiple thereof.

SECTION 303. EXECUTION, AUTHENTICATION, DELIVERY AND DATING.

     The Securities shall be executed on behalf of the Company by its Chairman of the Board, its Chief Executive Officer, its Chief Financial Officer, its President or any Vice President and need not be attested. The signature of any of these officers on the Securities may be manual or facsimile.

     Securities bearing the manual or facsimile signatures of individuals who were at any time the proper officers of the Company shall bind the Company, notwithstanding that such individuals or any of them have ceased to hold such offices prior to the authentication and delivery of such Securities or did not hold such offices at the date of such Securities.

     At any time and from time to time after the execution and delivery of this Indenture, the Company may deliver Securities of any series executed by the Company to the Trustee for authentication, together with a Company Order for the authentication and delivery of such Securities, and the Trustee in accordance with the Company Order shall authenticate and deliver such Securities; provided, however, that in the case of Securities offered in a Periodic Offering, the Trustee shall authenticate and deliver such Securities from time to time in accordance with such other procedures (including, without limitation, the receipt by the Trustee of oral or electronic instructions from the Company or its duly authorized agents, thereafter promptly confirmed in writing) acceptable to the Trustee as may be specified by or pursuant to a Company Order delivered to the Trustee prior to the time of the first authentication of Securities of such series. If the form or terms of the Securities of the series have been established in or pursuant to one or more Board Resolutions as permitted by Sections 201 and 301, in authenticating such Securities, and accepting the additional responsibilities under this Indenture in relation to such Securities, the Trustee shall be entitled to receive, and (subject to Section 601) shall be fully protected in relying upon, an Opinion of Counsel stating,

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               (1) if the form or forms of such Securities have been established by or pursuant to Board Resolution as permitted by Section 201, that such form or forms have been established in conformity with the provisions of this Indenture;

               (2) if the terms of such Securities have been, or in the case of Securities of a series offered in a Periodic Offering, will be, established by or pursuant to a Board Resolution as permitted by Section 301, that such terms have been, or in the case of Securities of a series offered in a Periodic Offering, will be, established in conformity with the provisions of this Indenture, subject, in the case of Securities of a series offered in a Periodic Offering, to any conditions specified in such Opinion of Counsel; and

               (3) that such Securities, when authenticated and delivered by the Trustee and issued by the Company in the manner and subject to any conditions specified in such Opinion of Counsel, will constitute valid and legally binding obligations of the Company enforceable in accordance with their terms, subject to bankruptcy, insolvency, fraudulent transfer, reorganization, moratorium and similar laws of general applicability relating to or affecting creditors’ rights and to general equity principles.

If such form or forms or terms have been so established, the Trustee shall not be required to authenticate such Securities if the issue of such Securities pursuant to this Indenture will affect the Trustee’s own rights, duties or immunities under the Securities and this Indenture or otherwise in a manner which is not reasonably acceptable to the Trustee.

     Notwithstanding the provisions of Section 301 and of the preceding paragraph, if all Securities of a series are not to be originally issued at one time, it shall not be necessary to deliver the Officer’s Certificate otherwise required pursuant to Section 301 or the Company Order and Opinion of Counsel otherwise required pursuant to such preceding paragraph at or prior to the time of authentication of each Security of such series if such documents are delivered at or prior to the authentication upon original issuance of the first Security of such series to be issued.

     With respect to Securities of a series offered in a Periodic Offering, the Trustee may rely, as to the authorization by the Company of any of such Securities, the form or forms and terms thereof and the legality, validity, binding effect and enforceability thereof, upon the Opinion of Counsel and the other documents delivered pursuant to Sections 201 and 301 and this Section, as applicable, in connection with the first authentication of Securities of such series.

     Each Security shall be dated the date of its authentication.

     No Security shall be entitled to any benefit under this Indenture or be valid or obligatory for any purpose unless there appears on such Security a certificate of authentication substantially in the form provided for herein executed by the Trustee by manual signature of an authorized officer, and such certificate upon any Security shall be conclusive evidence, and the only evidence, that such Security has been duly authenticated and delivered hereunder. Notwithstanding the foregoing, if any

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Security shall have been authenticated and delivered hereunder but never issued and sold by the Company, and the Company shall deliver such Security to the Trustee for cancellation as provided in Section 309 for all purposes of this Indenture such Security shall be deemed never to have been authenticated and delivered hereunder and shall never be entitled to the benefits of this Indenture.

SECTION 304. TEMPORARY SECURITIES.

     Pending the preparation of Definitive Securities of any series, the Company may execute, and upon Company Order the Trustee shall authenticate and deliver, temporary Securities which are printed, lithographed, typewritten, mimeographed or otherwise produced, in any authorized denomination, substantially of the tenor of the Definitive Securities in lieu of which they are issued and with such appropriate insertions, omissions, substitutions and other variations as the officers executing such Securities may determine, as evidenced by their execution of such Securities.

     If temporary Securities of any series are issued, the Company will cause Definitive Securities of that series to be prepared without unreasonable delay. After the preparation of Definitive Securities of such series, the temporary Securities of such series shall be exchangeable for Definitive Securities of such series upon surrender of the temporary Securities of such series at the office or agency of the Company maintained pursuant to Section 1002 for the purpose of exchanges of Securities of such series, without charge to the Holder. Upon surrender for cancellation of any one or more temporary Securities of any series the Company shall execute and the Trustee shall authenticate and deliver in exchange therefor one or more Definitive Securities of the same series, of any authorized denominations and of a like aggregate principal amount and tenor. Until so exchanged the temporary Securities of any series shall in all respects be entitled to the same benefits under this Indenture as Definitive Securities of such series and tenor.

SECTION 305. REGISTRATION, REGISTRATION OF TRANSFER AND EXCHANGE.

     The Company shall cause to be kept at an office or agency of the Company in The City of New York a register (the register maintained in such office or in any other office or agency of the Company in a Place of Payment being herein sometimes referred to as the “Security Register”) in which, subject to such reasonable regulations as it may prescribe, the Company shall provide for the registration of Securities and of transfers of Securities. The Company will prior to the issuance of any Securities hereunder, appoint the Trustee as the initial “Security Registrar” for the purpose of registering Securities and transfers of Securities as herein provided and its corporate trust office which, at the date hereof, is located at 450 West 33rd Street, New York, New York 10001 as the initial office or agency in The City of New York where the Security Register will be maintained. The Company may at any time replace such Security Registrar, change such office or agency or act as its own Security Registrar. The Company will give prompt written notice to the Trustee of any change of the Security Registrar or of the location of such office or agency.

     Upon surrender for registration of transfer of any Security of any series at the office or agency of the Company maintained pursuant to Section 1002 for such purpose, the Company shall

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execute, and the Trustee shall authenticate and deliver, in the name of the designated transferee or transferees, one or more new Securities of the same series, of any authorized denominations and of a like aggregate principal amount and tenor.

     At the option of the Holder, Securities of any series (except a Global Security) may be exchanged for other Securities of the same series, of any authorized denominations and of a like aggregate principal amount and tenor, upon surrender of the Securities to be exchanged at such office or agency. Whenever any Securities are so surrendered for exchange, the Company shall execute, and the Trustee shall authenticate and deliver, the Securities which the Holder making the exchange is entitled to receive.

     All Securities issued upon any registration of transfer or exchange of Securities shall be the valid obligations of the Company, evidencing the same debt, and entitled to the same benefits under this Indenture, as the Securities surrendered upon such registration of transfer or exchange.

     Every Security presented or surrendered for registration of transfer or for exchange shall (if so required by the Company or the Trustee) be duly endorsed, or be accompanied by a written instrument of transfer in form satisfactory to the Company and the Security Registrar duly executed, by the Holder thereof or his attorney duly authorized in writing.

     No service charge shall be made for any registration of transfer or exchange of Securities, but the Company may require payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in connection with any registration of transfer or exchange of Securities, other than exchanges pursuant to Section 304, 906 or 1107 not involving any transfer.

     The Company shall not be required (1) to issue, register the transfer of or exchange Securities of any series during a period beginning at the opening of business 15 days before the day of the mailing of a notice of redemption of Securities of that series selected for redemption under Section 1103 and ending at the close of business on the day of such mailing, or (2) to register the transfer of or exchange any Security so selected for redemption in whole or in part, except the unredeemed portion of any Security being redeemed in part.

     Notwithstanding any other provision in this Indenture and except as otherwise specified as contemplated by Section 301, no Global Security may be transferred to, or registered or exchanged for Securities registered in the name of, any Person other than the Depositary for such Global Security or any nominee thereof, and no such transfer may be registered, except as provided in this paragraph. Every Security authenticated and delivered upon registration or transfer of, or in exchange for or in lieu of, a Global Security shall be a Global Security, except as provided in this paragraph. If(1)(A) the Depositary for a Global Security notifies the Company that it is unwilling or unable to continue as Depositary for such Global Security or ceases to be a clearing agency registered under the Exchange Act, and (B) a successor Depositary is not appointed by the Company within 90 days, or (2) the Company determines in its sole discretion that Securities of a series issued in global form shall no longer be represented by a Global Security, then such Global Security may

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be exchanged by such Depositary for Definitive Securities of the same series, of any authorized denomination and of a like aggregate principal amount and tenor, registered in the names of, and the transfer of such Global Security or portion thereof may be registered to, such Persons as such Depositary shall direct.

SECTION 306. MUTILATED, DESTROYED, LOST AND STOLEN SECURITIES.

     If any mutilated Security is surrendered to the Trustee, together with, in proper cases, such security or indemnity as may be required by the Company or the Trustee to save each of them and any agent of either of them harmless, the Company shall execute and the Trustee shall authenticate and deliver in exchange therefor a new Security of the same series and of like tenor and principal amount and bearing a number not contemporaneously outstanding.

     If there shall be delivered to the Company and the Trustee (i) evidence to their satisfaction of the destruction, loss or theft of any Security and (ii) such security or indemnity as may be required by them to save each of them and any agent of either of them harmless, then, in the absence of notice to the Company or the Trustee that such Security has been acquired by a bona fide purchaser, the Company shall execute and the Trustee shall authenticate and deliver, in lieu of any such destroyed, lost or stolen Security, a new Security of the same series and of like tenor and principal amount and bearing a number not contemporaneously outstanding.

     In case any such mutilated, destroyed, lost or stolen Security has become or is about to become due and payable, the Company in its discretion may, instead of issuing a new Security, pay such Security.

     Upon the issuance of any new Security under this Section, the Company may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in relation thereto and any other expenses (including the fees and expenses of the Trustee) connected therewith.

     Every new Security of any series issued pursuant to this Section in exchange for any mutilated Security or in lieu of any destroyed, lost or stolen Security shall constitute an original additional contractual obligation of the Company, whether or not the mutilated, destroyed, lost or stolen Security shall be at any time enforceable by anyone, and shall be entitled to all the benefits of this Indenture equally and proportionately with any and all other Securities of that series duly issued hereunder.

     The provisions of this Section are exclusive and shall preclude (to the extent lawful) all other rights and remedies with respect to the replacement or payment of mutilated, destroyed, lost or stolen Securities.

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SECTION 307. PAYMENT OF INTEREST; INTEREST RIGHTS PRESERVED.

     Except as otherwise provided as contemplated by Section 301 with respect to any series of Securities, interest on any Security which is payable, and is punctually paid or duly provided for, on any Interest Payment Date shall be paid to the Person in whose name that Security (or one or more Predecessor Securities) is registered at the close of business on the Regular Record Date for such interest.

     Any interest on any Security of any series which is payable, but is not punctually paid or duly provided for, on any Interest Payment Date (herein called “Defaulted Interest”) shall forthwith cease to be payable to the Holder on the relevant Regular Record Date by virtue of having been such Holder, and such Defaulted Interest may be paid by the Company, at its election in each case, as provided in Clause (1) or (2) below:

               (1) The Company may elect to make payment of any Defaulted Interest to the Persons in whose names the Securities of such series (or their respective Predecessor Securities) are registered at the close of business on a Special Record Date for the payment of such Defaulted Interest, which shall be fixed in the following manner. The Company shall notify the Trustee in writing of the amount of Defaulted Interest proposed to be paid on each Security of such series and the date of the proposed payment, and at the same time the Company shall deposit with the Trustee an amount of money equal to the aggregate amount proposed to be paid in respect of such Defaulted Interest or shall make arrangements satisfactory to the Trustee for such deposit prior to the date of the proposed payment, such money when deposited to be held in trust for the benefit of the Persons entitled to such Defaulted Interest as in this Clause provided. Thereupon the Trustee shall fix a Special Record Date for the payment of such Defaulted Interest which shall be not more than 15 days and not less than 10 days prior to the date of the proposed payment and not less than 10 days after the receipt by the Trustee of the notice of the proposed payment. The Trustee shall promptly notify the Company of such Special Record Date and, in the name and at the expense of the Company, shall cause notice of the proposed payment of such Defaulted Interest and the Special Record Date therefor to be mailed, first-class postage prepaid, to each Holder of Securities of such series at his address as it appears in the Security Register, not less than 10 days prior to such Special Record Date. Notice of the proposed payment of such Defaulted Interest and the Special Record Date therefor having been so mailed, such Defaulted Interest shall be paid to the Persons in whose names the Securities of such series (or their respective Predecessor Securities) are registered at the close of business on such Special Record Date and shall no longer be payable pursuant to the following Clause (2).

               (2) The Company may make payment of any Defaulted Interest on the Securities of any series in any other lawful manner not inconsistent with the requirements of any securities exchange on which such Securities may be listed, and upon such notice as may be required by such exchange, if, after notice given by the Company to the Trustee of the proposed payment pursuant to this Clause, such manner of payment shall be deemed practicable by the Trustee.

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     Subject to the foregoing provisions of this Section and Section 305, each Security delivered under this Indenture upon registration of transfer of or in exchange for or in lieu of any other Security shall carry the rights to interest accrued and unpaid, and to accrue, which were carried by such other Security.

SECTION 308. PERSONS DEEMED OWNERS.

     Except as otherwise provided as contemplated by Section 301 with respect to any series of Securities, prior to due presentment of a Security for registration of transfer, the Company, the Trustee and any agent of the Company or the Trustee may treat the Person in whose name such Security is registered as the owner of such Security for the purpose of receiving payment of principal of and any premium and (subject to Sections 305 and 307) any interest on such Security and for all other purposes whatsoever, whether or not such Security be overdue, and neither the Company, the Trustee nor any agent of the Company or the Trustee shall be affected by notice to the contrary.

     No holder of any beneficial interest in any Global Security held on its behalf by a Depositary shall have any rights under this Indenture with respect to such Global Security, and such Depositary may be treated by the Company, the Trustee, and any agent of the Company or the Trustee as the owner of such Global Security for all purposes whatsoever. None of the Company, the Trustee nor any agent of the Company or the Trustee will have any responsibility or liability for any aspect of the records relating to or payments made on account of beneficial ownership interests of a Global Security or for maintaining, supervising or reviewing any records relating to such beneficial ownership interests.

SECTION 309. CANCELLATION.

     All Securities surrendered for payment, redemption, registration of transfer or exchange or for credit against any sinking fund payment shall, if surrendered to any Person other than the Trustee, be delivered to the Trustee and shall be promptly canceled by it. The Company may at any time deliver to the Trustee for cancellation any Securities previously authenticated and delivered hereunder which the Company may have acquired in any manner whatsoever, and may deliver to the Trustee (or to any other Person for delivery to the Trustee) for cancellation any Securities previously authenticated hereunder which the Company has not issued and sold, and all Securities so delivered shall be promptly canceled by the Trustee. No Securities shall be authenticated in lieu of or in exchange for any Securities canceled as provided in this Section, except as expressly permitted by this Indenture. All canceled Securities held by the Trustee shall be disposed of in accordance with its customary procedures, and the Trustee shall thereafter deliver to the Company a certificate with respect to such disposition.

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SECTION 310. COMPUTATION OF INTEREST.

     Except as otherwise specified as contemplated by Section 301 for Securities of any series, interest on the Securities of each series shall be
computed on the basis of a 360-day year of twelve 30-day months.

SECTION 311. CUSIP NUMBERS.

     The Company in issuing the Securities may use “CUSIP” numbers (in addition to the other identification numbers printed on the Securities), and, if so, the Trustee shall use “CUSIP” numbers in notices of redemption as a convenience to Holders; provided, however, that any such notice may state that no representation is made as to the correctness of such “CUSIP” numbers either as printed on the Securities or as contained in any notice of a redemption and that reliance may be placed only on the other identification numbers printed on the Securities, and any such redemption shall not be affected by any defect in or omission of such “CUSIP” numbers.

ARTICLE FOUR

SATISFACTION AND DISCHARGE

SECTION 401. SATISFACTION AND DISCHARGE OF INDENTURE.

     This Indenture shall upon Company Request cease to be of further effect with respect to Securities of any series (except as to any surviving rights of registration of transfer or exchange of such Securities herein expressly provided for), and the Trustee, at the expense of the Company, shall execute proper instruments acknowledging satisfaction and discharge of this Indenture with respect to such Securities, when

(1) either

                         (A) all such Securities theretofore authenticated and delivered (other than (i) such Securities which have been destroyed, lost or stolen and which have been replaced or paid as provided in Section 306, and (ii) such Securities for whose payment money has theretofore been deposited in trust or segregated and held in trust by the Company and thereafter repaid to the Company or discharged from such trust, as provided in Section 1003) have been delivered to the Trustee for cancellation; or

                         (B) all such Securities not theretofore delivered to the Trustee for cancellation

               (i) have become due and payable, or

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               (ii) will become due and payable at their Stated Maturity within one year, or

               (iii) are to be called for redemption within one year under arrangements satisfactory to the Trustee for the giving of notice of redemption by the Trustee in the name, and at the expense, of the Company,

and the Company in the case of (i), (ii) or (iii) above, has deposited or caused to be deposited with the Trustee as trust funds in trust for the purpose an amount of money in the currency or currency units in which such Securities are payable sufficient to pay and discharge the entire indebtedness on such Securities not theretofore delivered to the Trustee for cancellation, for principal and any premium and interest to the date of such deposit (in the case of Securities which have become due and payable) or to the Stated Maturity or Redemption Date, as the case may be;

               (2) the Company has paid or caused to be paid all other sums payable hereunder by the Company with respect to such Securities; and

               (3) the Company has delivered to the Trustee an Officer’s Certificate and an Opinion of Counsel, each stating that all conditions precedent herein provided for relating to the satisfaction and discharge of this Indenture with respect to such Securities have been complied with.

     Notwithstanding the satisfaction and discharge of this Indenture with respect to Securities of any series, (x) the obligations of the Company to the Trustee under Section 607, the obligations of the Trustee to any Authenticating Agent under Section 614 and the right of the Trustee to resign under Section 610 shall survive, and (y) if money shall have been deposited with the Trustee pursuant to subclause (B) of Clause (1) of this Section, the obligations of the Company and/or the Trustee under Sections 402, 606, 701 and 1002 and the last paragraph of Section 1003 shall survive.

SECTION 402. APPLICATION OF TRUST MONEY.

     Subject to the provisions of the last paragraph of Section 1003, all money deposited with the Trustee pursuant to Section 401 shall be held in trust and applied by it, in accordance with the provisions of the Securities and this Indenture, to the payment, either directly or through any Paying Agent (including the Company acting as its own Paying Agent) as the Trustee may determine, to the Persons entitled thereto, of the principal and any premium and interest for whose payment such money has been deposited with the Trustee.

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ARTICLE FIVE

REMEDIES

SECTION 501. EVENTS OF DEFAULT.

     “Event of Default”, wherever used herein with respect to Securities of any series, means any one of the following events (whatever the reason for such Event of Default and whether it shall be voluntary or involuntary or be effected by operation of law or pursuant to any judgment, decree or order of any court or any order, rule or regulation of any administrative or governmental body):

               (1) default in the payment of any interest upon any Security of that series when it becomes due and payable, and continuance of such default for a period of 30 days; or

               (2) default in the payment of the principal of (or premium, if any, on) any Security of that series at its Maturity; or

               (3) default in the performance, or breach, of any term, covenant or warranty of the Company in this Indenture (other than a term, covenant or warranty a default in whose performance or whose breach is elsewhere in this Section specifically dealt with or which has expressly been included in this Indenture solely for the benefit of series of Securities other than that series), and continuance of such default or breach for a period of 60 days after there has been given, by registered or certified mail, to the Company by the Trustee or to the Company and the Trustee by the Holders of at least 25% in principal amount of the Outstanding Securities of that series a written notice specifying such default or breach and requiring it to be remedied and stating that such notice is a “Notice of Default” hereunder; or

               (4) the Company pursuant to or within the meaning of any Bankruptcy Law (A) commences a voluntary case, (B) consents to the entry of any order for relief against it in an involuntary case, (C) consents to the appointment of a Custodian of it or for all or substantially all of its property, or (D) makes a general assignment for the benefit of its creditors; or

               (5) a court of competent jurisdiction enters an order or decree under any Bankruptcy Law that (A) is for relief against the Company in an involuntary case, (B) appoints a Custodian of the Company or for all or substantially all of its property, or (C) orders the liquidation of the Company; and the order or decree remains unstayed and in effect for 90 days; or

               (6) any other Event of Default provided as contemplated by Section 301 with respect to Securities of that series.

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SECTION 502. ACCELERATION OF MATURITY; RESCISSION AND ANNULMENT.

     If an Event of Default with respect to Securities of any series at the time Outstanding occurs and is continuing, then in every such case the Trustee or the Holders of not less than 25% in principal amount of the Outstanding Securities of that series may declare the principal amount (or, if any of the Securities of that series are Original Issue Discount Securities, such portion of the principal amount of such Securities as may be specified in the terms thereof) of all of the Securities of that series to be due and payable immediately, by a notice in writing to the Company (and to the Trustee if given by Holders), and upon any such declaration such principal amount (or specified amount) shall become immediately due and payable.

     At any time after such a declaration of acceleration with respect to Securities of any series has been made and before a judgment or decree for payment of the money due has been obtained by the Trustee as hereinafter in this Article provided, the Holders of a majority in principal amount of the Outstanding Securities of that series, by written notice to the Company and the Trustee, may rescind and annul such declaration and its consequences if

               (1) the Company has paid or deposited with the Trustee a sum sufficient to pay

                    (A) all overdue interest on all Securities of that series,

                    (B) the principal of (and premium, if any, on) any Securities of that series which have become due otherwise than by such declaration of acceleration and any interest thereon at the rate or rates prescribed therefor in such Securities,

                    (C) to the extent that payment of such interest is lawful, interest upon overdue interest at the rate or rates prescribed
therefor in such Securities, and

                    (D) all sums paid or advanced by the Trustee hereunder and the reasonable compensation, expenses, disbursements and
advances of the Trustee, its agents and counsel;

and

               (2) all Events of Default with respect to Securities of that series, other than the non-payment of the principal of Securities of that series which have become due solely by such declaration of acceleration, have been cured or waived as provided in Section 513.

     No such rescission shall affect any subsequent Default or impair any right consequent thereon.

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SECTION 503. COLLECTION OF INDEBTEDNESS AND SUITS FOR ENFORCEMENT BY TRUSTEE.

     The Company covenants that if

               (1) default is made in the payment of any interest on any Security when such interest becomes due and payable and such default continues for a period of 30 days, or

               (2) default is made in the payment of the principal of (or premium, if any, on) any Security at the Maturity thereof,

the Company will, upon demand of the Trustee, pay to it, for the benefit of the Holders of such Securities, the whole amount then due and payable on such Securities for principal and any premium and interest and, to the extent that payment of such interest shall be legally enforceable, interest on any overdue principal and premium and on any overdue interest, at the rate or rates prescribed therefor in such Securities, and, in addition thereto, such further amount as shall be sufficient to cover the costs and expenses of collection, including the reasonable compensation, expenses, disbursements and advances of the Trustee, its agents and counsel.

     If the Company fails to pay such amounts forthwith upon such demand, the Trustee, in its own name and as trustee of an express trust, may institute a judicial proceeding for the collection of the sums so due and unpaid, may prosecute such proceeding to judgment or final decree and may enforce the same against the Company or any other obligor upon such Securities and collect the moneys adjudged or decreed to be payable in the manner provided by law out of the property of the Company or any other obligor upon such Securities, wherever situated.

     If an Event of Default with respect to Securities of any series occurs and is continuing, the Trustee may in its discretion proceed to protect and enforce its rights and the rights of the Holders of Securities of such series by such appropriate judicial proceedings as the Trustee shall deem most effectual to protect and enforce any such rights, whether for the specific enforcement of any covenant or agreement in this Indenture or in aid of the exercise of any power granted herein, or to enforce any other proper remedy.

SECTION 504. TRUSTEE MAY FILE PROOFS OF CLAIM.

     In case of any judicial proceeding relative to the Company or any other obligor upon the Securities, their property or their creditors, the Trustee shall be entitled and empowered, by intervention in such proceeding or otherwise, to take any and all actions authorized under the Trust Indenture Act in order to have claims of the Holders and the Trustee allowed in any such proceeding. In particular, the Trustee shall be authorized to collect and receive any moneys or other property payable or deliverable on any such claims and to distribute the same; and any custodian, receiver, assignee, trustee, liquidator, sequestrator or other similar official in any such judicial proceeding is hereby authorized by each Holder to make such payments to the Trustee and, in the event that the Trustee shall consent to the making of such payments directly to the Holders, to pay to the Trustee

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any amount due it for the reasonable compensation, expenses, disbursements and advances of the Trustee, its agents and counsel, and any other amounts due the Trustee under Section 607.

     No provision of this Indenture shall be deemed to authorize the Trustee to authorize or consent to or accept or adopt on behalf of any Holder any plan of reorganization, arrangement, adjustment or composition affecting the Securities or the rights of any Holder thereof or to authorize the Trustee to vote in respect of the claim of any Holder in any such proceeding; provided, however, that the Trustee may, on behalf of the Holders, vote for the election of a trustee in bankruptcy or similar official and be a member of a creditors’ or other similar committee.

SECTION 505. TRUSTEE MAY ENFORCE CLAIMS WITHOUT POSSESSION OF SECURITIES.

     All rights of action and claims under this Indenture or the Securities may be prosecuted and enforced by the Trustee without the possession of any of the Securities or the production thereof in any proceeding relating thereto, and any such proceeding instituted by the Trustee shall be brought in its own name as trustee of an express trust, and any recovery of judgment shall, after provision for the payment of the reasonable compensation, expenses, disbursements and advances of the Trustee, its agents and counsel, be for the ratable benefit of the Holders of the Securities in respect of which such judgment has been recovered.

SECTION 506. APPLICATION OF MONEY COLLECTED.

     Any money collected by the Trustee pursuant to this Article shall be applied in the following order, at the date or dates fixed by the Trustee and, in case of the distribution of such money on account of principal or any premium or interest, upon presentation of the Securities and the notation thereon of the payment if only partially paid and upon surrender thereof if fully paid:

     FIRST: To the payment of all amounts due the Trustee under Section 607;

     SECOND: To the payment of the amounts then due and unpaid for principal of and any premium and interest on the Securities in respect of which or for the benefit of which such money has been collected, ratably, without preference or priority of any kind, according to the amounts due and payable on such Securities for principal and any premium and interest, respectively; and

     THIRD: The balance, if any, to the Company.

SECTION 507. LIMITATION ON SUITS.

     No Holder of any Security of any series shall have any right to institute any proceeding, judicial or otherwise, with respect to this Indenture, or for the appointment of a receiver or trustee, or for any other remedy hereunder, unless

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          (1) such Holder has previously given written notice to the Trustee of a continuing Event of Default with respect to the Securities of that series;

          (2) the Holders of not less than 25% in principal amount of the Outstanding Securities of that series shall have made written request to the Trustee to institute proceedings in respect of such Event of Default in its own name as Trustee hereunder;

          (3) such Holder or Holders have offered to the Trustee reasonable indemnity against the costs, expenses and liabilities to be incurred in compliance with such request;

          (4) the Trustee for 60 days after its receipt of such notice, request and offer of indemnity has failed to institute any such proceeding; and

          (5) no direction inconsistent with such written request has been given to the Trustee during such 60-day period by the Holders of a majority in principal amount of the Outstanding Securities of that series;

it being understood and intended that no one or more of such Holders shall have any right in any manner whatever by virtue of, or by availing of, any provision of this Indenture to affect, disturb or prejudice the rights of any other of such Holders, or to obtain or to seek to obtain priority or preference over any other of such Holders or to enforce any right under this Indenture, except in the manner herein provided and for the equal and ratable benefit of all of such Holders.

SECTION 508. UNCONDITIONAL RIGHT OF HOLDERS TO RECEIVE PRINCIPAL, PREMIUM AND INTEREST.

     Notwithstanding any other provision in this Indenture, the Holder of any Security shall have the right, which is absolute and unconditional, to receive payment of the principal of and any premium and (subject to Sections 305 and 307) interest on such Security on the respective Stated Maturities expressed in such Security (or, in the case of redemption, on the Redemption Date) and to institute suit for the enforcement of any such payment, and such rights shall not be impaired without the consent of such Holder.

SECTION 509. RESTORATION OF RIGHTS AND REMEDIES.

     If the Trustee or any Holder has instituted any proceeding to enforce any right or remedy under this Indenture and such proceeding has been discontinued or abandoned for any reason, or has been determined adversely to the Trustee or to such Holder, then and in every such case, subject to any determination in such proceeding, the Company, the Trustee and the Holders shall be restored severally and respectively to their former positions hereunder, and thereafter all rights and remedies of the Trustee and the Holders shall continue as though no such proceeding had been instituted.

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SECTION 510. Rights and Remedies Cumulative.

     Except as otherwise provided with respect to the replacement or payment of mutilated, destroyed, lost or stolen Securities in the last paragraph of Section 306, no right or remedy herein conferred upon or reserved to the Trustee or to the Holders is intended to be exclusive of any other right or remedy, and every right and remedy shall, to the extent permitted by law, be cumulative and in addition to every other right and remedy given hereunder or now or hereafter existing at law or in equity or otherwise. The assertion or employment of any right or remedy hereunder, or otherwise, shall not prevent the concurrent assertion or employment of any other appropriate right or remedy.

SECTION 511. DELAY OR OMISSION NOT WAIVER.

     No delay or omission of the Trustee or of any Holder of any Securities to exercise any right or remedy accruing upon any Event of Default shall impair any such right or remedy or constitute a waiver of any such Event of Default or an acquiescence therein. Every right and remedy given by this Article or by law to the Trustee or to the Holders may be exercised from time to time, and as often as may be deemed expedient, by the Trustee or by the Holders, as the case may be.

SECTION 512. CONTROL BY HOLDERS.

     The Holders of a majority in aggregate principal amount of the Outstanding Securities of any series shall have the right to direct the time, method and place of conducting any proceeding for any remedy available to the Trustee, or exercising any trust or power conferred on the Trustee, with respect to the Securities of such series; provided, however, that

          (1) such direction shall not be in conflict with any rule of law or with this Indenture;

          (2) the Trustee may take any other action deemed proper by the Trustee which is not inconsistent with such direction; and

          (3) subject to the provisions of Section 601, the Trustee shall have the right to decline to follow any such direction if the Trustee in good faith shall determine that the proceeding so directed would involve the Trustee in personal liability.

SECTION 513. Waiver of Past Defaults.

     The Holders of a majority in aggregate principal amount of the Outstanding Securities of any series may on behalf of the Holders of all the Securities of such series waive any past default hereunder with respect to such series and its consequences, except

          (1) a continuing default in the payment of the principal of or any premium or interest on any Security of such series, or

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          (2) a default in respect of a covenant or provision hereof which under Article Nine cannot be modified or amended without the consent of the Holder of each Outstanding Security of such series affected.

     Upon any such waiver, such default shall cease to exist, and any Event of Default arising therefrom shall be deemed to have been cured, for every purpose of this Indenture, but no such waiver shall extend to any subsequent or other default or impair any right consequent thereon.

SECTION 514. UNDERTAKING FOR COSTS.

     In any suit for the enforcement of any right or remedy under this Indenture, or in any suit against the Trustee for any action taken, suffered or omitted by it as Trustee, a court may require any party litigant in such suit to file an undertaking to pay the costs of such suit, and may assess costs against any such party litigant, in the manner and to the extent provided in the Trust Indenture Act; provided, however, that neither this Section nor the Trust Indenture Act shall be deemed to authorize any court to require such an undertaking or to make such an assessment in any suit instituted by the Company.

SECTION 515. WAIVER OF USURY, STAY OR EXTENSION LAWS.

     The Company covenants (to the extent that it may lawfully do so) that it will not at any time insist upon, or plead, or in any manner whatsoever claim or take the benefit or advantage of, any usury, stay or extension law wherever enacted, now or at any time hereafter in force, which may affect the covenants or the performance of this Indenture; and the Company (to the extent that it may lawfully do so) hereby expressly waives all benefit or advantage of any such law and covenants that it will not hinder, delay or impede the execution of any power herein granted to the Trustee, but will suffer and permit the execution of every such power as though no such law had been enacted.

ARTICLE SIX

THE TRUSTEE

SECTION 601. CERTAIN DUTIES AND RESPONSIBILITIES.

     The duties and responsibilities of the Trustee shall be as provided by the Trust Indenture Act. No provision of this Indenture shall require the Trustee to expend or risk its own funds or otherwise incur any financial liability in the performance of any of its duties hereunder, or in the exercise of any of its rights or powers, if it shall have reasonable grounds for believing that repayment of such funds or adequate indemnity against such risk or liability is not reasonably assured to it. Whether or not therein expressly so provided, every provision of this Indenture relating to the conduct or affecting the liability of or affording protection to the Trustee shall be subject to the provisions of this Section.

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SECTION 602. NOTICE OF DEFAULTS.

     If a Default occurs and is continuing with respect to the Securities of any series, the Trustee shall, within 90 days after it occurs, transmit, in the manner and to the extent provided in Section 313(c) of the Trust Indenture Act, notice of all uncured or unwaived Defaults known to it; provided, however, that, except in the case of a Default in payment on the Securities of any series, the Trustee may withhold the notice if and so long as the board of directors, the executive committee or a trust committee of its directors and/or its duly authorized officers in good faith determines that withholding such notice is in the interests of Holders of Securities of such series; provided further, however, that, in the case of any default or breach of the character specified in Section 501(3) with respect to the Securities of such series, no such notice to Holders shall be given until at least 60 days after the occurrence thereof.

SECTION 603. CERTAIN RIGHTS OF TRUSTEE.

     Subject to the provisions of Section 601:

          (1) the Trustee may rely on and shall be protected in acting or refraining from acting upon any resolution, certificate, statement, instrument, opinion, report, notice, request, direction, consent, order, bond, debenture, note, other evidence of indebtedness or other paper or document reasonably believed by it to be genuine and to have been signed or presented by the proper party or parties;

          (2) any request, direction, order or demand of the Company mentioned herein shall be sufficiently evidenced by a Company Request or Company Order (other than delivery of any Security to the Trustee for authentication and delivery pursuant to Section 303, which shall be sufficiently evidenced as provided therein) and any resolution of the Board of Directors shall be sufficiently evidenced by a Board Resolution;

          (3) whenever in the administration of this Indenture the Trustee shall deem it desirable that a matter be proved or established prior to taking, suffering or omitting any action hereunder, the Trustee (unless other evidence be herein specifically prescribed) may, in the absence of bad faith on its part, rely upon an Officer’s Certificate;

          (4) the Trustee may consult with counsel and the written advice of such counsel or any Opinion of Counsel shall be full and complete authorization and protection in respect of any action taken, suffered or omitted by it hereunder in good faith and in reliance thereon;

          (5) the Trustee shall be under no obligation to exercise any of the rights or powers vested in it by this Indenture at the request or direction of any of the Holders pursuant to this Indenture, unless such Holders shall have offered to the Trustee reasonable security or indemnity against the costs, expenses and liabilities which might be incurred by it in compliance with such request or direction;

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          (6) the Trustee shall not be bound to make any investigation into the facts or matters stated in any resolution, certificate, statement, instrument, opinion, report, notice, request, direction, consent, order, bond, debenture, note, other evidence of indebtedness or other paper or document but the Trustee, in its discretion, may make such further inquiry or investigation into such facts or matters as it may see fit;

          (7) the Trustee may execute any of the trusts or powers hereunder or perform any duties hereunder either directly or by or through agents or attorneys and the Trustee shall not be responsible for any misconduct or negligence on the part of any agent or attorney appointed with due care by it hereunder; and

          (8) the Trustee may request that the Company deliver an Officer’s Certificate setting forth the names of individuals and/or titles of officers authorized at such time to take specified actions pursuant to this Indenture, which Officer’s Certificate may be signed by any person authorized to sign an Officer’s Certificate, including any person specified as so authorized in any such certificate previously delivered and not superseded.

SECTION 604. NOT RESPONSIBLE FOR RECITALS OR ISSUANCE OF SECURITIES.

     The recitals contained herein and in the Securities, except the Trustee’s certificates of authentication, shall be taken as the statements of the Company, and the Trustee or any Authenticating Agent assumes no responsibility for their correctness. Neither the Trustee nor any Authenticating Agent makes any representations as to the validity or sufficiency of this Indenture or of the Securities. The Trustee or any Authenticating Agent shall not be accountable for the use or application by the Company of Securities or the proceeds thereof.

SECTION 605. MAY HOLD SECURITIES.

     The Trustee, any Authenticating Agent, any Paying Agent, any Security Registrar or any other agent of the Company, in its individual or any other capacity, may become the owner or pledgee of Securities and, subject to Sections 608 and 613, may otherwise deal with the Company with the same rights it would have if it were not Trustee, Authenticating Agent, Paying Agent, Security Registrar or such other agent.

SECTION 606. MONEY HELD IN TRUST.

     Money held by the Trustee in trust hereunder need not be segregated from other funds except to the extent required by law. The Trustee shall be under no liability for interest on any money received by it hereunder except as otherwise agreed with the Company.

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SECTION 607. COMPENSATION AND REIMBURSEMENT.

     The Company agrees

          (1) to pay to the Trustee from time to time reasonable compensation for all services rendered by it hereunder (which compensation shall not be limited by any provision of law in regard to the compensation of a trustee of an express trust);

          (2) except as otherwise expressly provided herein, to reimburse the Trustee upon its request for all reasonable expenses, disbursements and advances incurred or made by the Trustee in accordance with any provision of this Indenture (including the reasonable compensation and the expenses and disbursements of its agents and counsel), except any such expense, disbursement or advance as may be attributable to its negligence or bad faith; and

          (3) to indemnify the Trustee for, and to hold it harmless against, any loss, liability or expense incurred without negligence or bad faith on its part, arising out of or in connection with the acceptance or administration of the trust or trusts hereunder, including the costs and expenses of defending itself against any claim or liability in connection with the exercise or performance of any of its powers or duties hereunder, except those attributable to its negligence or bad faith.

     The obligations of the Company under this Section to compensate the Trustee and to pay or reimburse the Trustee for expenses, disbursements and advances shall constitute additional indebtedness hereunder. Such additional indebtedness shall be secured by a lien prior to that of the Securities upon all property and funds held or collected by the Trustee as such, except funds held in trust for the benefit of the Holders of particular Securities.

     Without limiting any rights available to the Trustee under applicable law, when the Trustee incurs expenses or renders services in connection with an Event of Default specified in Section 501(4) or Section 501(5), the expenses (including the reasonable charges and expenses of its counsel) and the compensation for such services are intended to constitute expenses of administration under any applicable Bankruptcy Law.

     The provisions of this Section shall survive the satisfaction and discharge of this Indenture and the defeasance of the Securities.

SECTION 608. DISQUALIFICATION; CONFLICTING INTERESTS.

     If the Trustee has or shall acquire a conflicting interest within the meaning of the Trust Indenture Act, the Trustee shall either eliminate such interest or resign, to the extent and in the manner provided by, and subject to the provisions of, the Trust Indenture Act and this Indenture.

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SECTION 609. CORPORATE TRUSTEE REQUIRED; ELIGIBILITY.

     There shall at all times be one or more Trustees hereunder with respect to the Securities of each series, at least one of which shall be a Person that is eligible pursuant to the Trust Indenture Act to act as such and has a combined capital and surplus required by the Trust Indenture Act. If such Person publishes reports of condition at least annually, pursuant to law or to the requirements of a supervising or examining authority, then for the purposes of this Section, the combined capital and surplus of such Person shall be deemed to be its combined capital and surplus as set forth in its most recent report of condition so published. If at any time the Trustee shall cease to be eligible in accordance with the provisions of this Section, it shall resign immediately in the manner and with the effect hereinafter specified in this Article.

SECTION 610. RESIGNATION AND REMOVAL; APPOINTMENT OF SUCCESSOR.

     No resignation or removal of the Trustee and no appointment of a successor Trustee pursuant to this Article shall become effective until the acceptance of appointment by the successor Trustee in accordance with the applicable requirements of Section 611.

     The Trustee may resign at any time with respect to the Securities of one or more series by giving written notice thereof to the Company. If the instrument of acceptance by a successor Trustee required by Section 611 shall not have been delivered to the Trustee within 30 days after the giving of such notice of resignation, the resigning Trustee may petition any court of competent jurisdiction for the appointment of a successor Trustee with respect to the Securities of such series.

     The Trustee may be removed at any time with respect to the Securities of any series by Act of the Holders of a majority in principal amount of the Outstanding Securities of such series, delivered to the Trustee and to the Company.

     If at any time:

          (1) the Trustee shall fail to comply with Section 608 after written request therefor by the Company or by any Holder who has been a bona fide Holder of a Security for at least six months, or

          (2) the Trustee shall cease to be eligible under Section 609 and shall fail to resign after written request therefor by the Company or by any such Holder, or

          (3) the Trustee shall become incapable of acting or shall be adjudged a bankrupt or insolvent or a receiver of the Trustee or of its property shall be appointed or any public officer shall take charge or control of the Trustee or of its property or affairs for the purpose of rehabilitation, conservation or liquidation, then, in any such case, (A) the Company may remove the Trustee with respect to all Securities, or (B) subject to Section 514, any Holder who has been a bona fide Holder of a Security for at least six months may, on behalf of himself and all others similarly

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situated, petition any court of competent jurisdiction for the removal of the Trustee with respect to all Securities and the appointment of a successor Trustee or Trustees.

     If the Trustee shall resign, be removed or become incapable of acting, or if a vacancy shall occur in the office of Trustee for any cause, with respect to the Securities of one or more series, the Company shall promptly appoint a successor Trustee or Trustees with respect to the Securities of that or those series (it being understood that any such successor Trustee may be appointed with respect to the Securities of one or more or all of such series and that at any time there shall be only one Trustee with respect to the Securities of any particular series) and shall comply with the applicable requirements of Section 611. If, within one year after such resignation, removal or incapability, or the occurrence of such vacancy, a successor Trustee with respect to the Securities of any series shall be appointed by Act of the Holders of a majority in principal amount of the Outstanding Securities of such series delivered to the Company and the retiring Trustee, the successor Trustee so appointed shall, forthwith upon its acceptance of such appointment in accordance with the applicable requirements of Section 611, become the successor Trustee with respect to the Securities of such series and to that extent supersede the successor Trustee appointed by the Company. If no successor Trustee with respect to the Securities of any series shall have been so appointed by the Company or the Holders and accepted appointment in the manner required by Section 611, any Holder who has been a bona fide Holder of a Security of such series for at least six months may, on behalf of himself and all others similarly situated, petition any court of competent jurisdiction for the appointment of a successor Trustee with respect to the Securities of such series.

     The Company shall give notice of each resignation and each removal of the Trustee with respect to the Securities of any series and each appointment of a successor Trustee with respect to the Securities of any series to all Holders of Securities of such series in the manner provided in Section 106. Each notice shall include the name of the successor Trustee with respect to the Securities of such series and the address of its Corporate Trust Office.

SECTION 611. Acceptance of Appointment by Successor.

          (a) In case of the appointment hereunder of a successor Trustee with respect to all Securities, every such successor Trustee so appointed shall execute, acknowledge and deliver to the Company and to the retiring Trustee an instrument accepting such appointment, and thereupon the resignation or removal of the retiring Trustee shall become effective and such successor Trustee, without any further act, deed or conveyance, shall become vested with all the rights, powers, trusts and duties of the retiring Trustee; but, on the request of the Company or the successor Trustee, such retiring Trustee shall, upon payment of its charges, execute and deliver an instrument transferring to such successor Trustee all the rights, powers and trusts of the retiring Trustee and shall duly assign, transfer and deliver to such successor Trustee all property and money held by such retiring Trustee hereunder.

          (b) In case of the appointment hereunder of a successor Trustee with respect to the Securities of one or more (but not all) series, the Company, the retiring Trustee and each

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successor Trustee with respect to the Securities of one or more series shall execute and deliver an indenture supplemental hereto wherein each successor Trustee shall accept such appointment and which (1) shall contain such provisions as shall be necessary or desirable to transfer and confirm to, and to vest in, each successor Trustee all the rights, powers, trusts and duties of the retiring Trustee with respect to the Securities of that or those series to which the appointment of such successor Trustee relates, (2) if the retiring Trustee is not retiring with respect to all Securities, shall contain such provisions as shall be deemed necessary or desirable to confirm that all the rights, powers, trusts and duties of the retiring Trustee with respect to the Securities of that or those series as to which the retiring Trustee is not retiring shall continue to be vested in the retiring Trustee, and (3) shall add to or change any of the provisions of this Indenture as shall be necessary to provide for or facilitate the administration of the trusts hereunder by more than one Trustee, it being understood that nothing herein or in such supplemental indenture shall constitute such Trustees as co-trustees of the same trust and that each such Trustee shall be trustee of a trust or trusts hereunder separate and apart from any trust or trusts hereunder administered by any other such Trustee; and upon the execution and delivery of such supplemental indenture the resignation or removal of the retiring Trustee shall become effective to the extent provided therein and each such successor Trustee, without any further act, deed or conveyance, shall become vested with all the rights, powers, trusts and duties of the retiring Trustee with respect to the Securities of that or those series to which the appointment of such successor Trustee relates; but, on request of the Company or any successor Trustee, such retiring Trustee shall duly assign, transfer and deliver to such successor Trustee all property and money held by such retiring Trustee hereunder with respect to the Securities of that or those series to which the appointment of such successor Trustee relates.

          (c) Upon request of any such successor Trustee, the Company shall execute any and all instruments for more fully and certainly vesting in and confirming to such successor Trustee all such rights, powers and trusts referred to in paragraph (a) or (b) of this Section, as the case may be.

          (d) No successor Trustee shall accept its appointment unless at the time of such acceptance such successor Trustee shall be qualified and eligible under this Article.

SECTION 612. Merger, Conversion, Consolidation or Succession to Business.

     Any corporation into which the Trustee may be merged or converted or with which it may be consolidated, or any corporation resulting from any merger, conversion or consolidation to which the Trustee shall be a party, or any corporation succeeding to all or substantially all the corporate trust business of the Trustee, shall be the successor of the Trustee hereunder, provided such corporation shall be otherwise qualified and eligible under this Article, without the execution or filing of any paper or any further act on the part of any of the parties hereto. In case any Securities shall have been authenticated, but not delivered, by the Trustee then in office, any successor by merger, conversion or consolidation to such authenticating Trustee may adopt such authentication and deliver the Securities so authenticated with the same effect as if such successor Trustee had itself authenticated such Securities.

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SECTION 613. Preferential Collection of Claims Against Company.

     If and when the Trustee shall be or become a creditor of the Company (or any other obligor upon the Securities), the Trustee shall be subject to the provisions of the Trust Indenture Act regarding the collection of claims against the Company (or any such other obligor).

SECTION 614. Appointment of Authenticating Agent.

     The Trustee (upon notice to the Company) may appoint an Authenticating Agent or Agents with respect to one or more series of Securities which shall be authorized to act on behalf of the Trustee to authenticate Securities of such series issued upon original issue (in accordance with procedures acceptable to the Trustee) and upon exchange, registration of transfer or partial redemption thereof or pursuant to Section 306, and Securities so authenticated shall be entitled to the benefits of this Indenture and shall be valid and obligatory for all purposes as if authenticated by the Trustee hereunder. Wherever reference is made in this Indenture to the authentication and delivery of Securities by the Trustee or the Trustee’s certificate of authentication, such reference shall be deemed to include authentication and delivery on behalf of the Trustee by an Authenticating Agent and a certificate of authentication executed on behalf of the Trustee by an Authenticating Agent. Each Authenticating Agent shall be acceptable to the Company and shall at all times be a corporation organized and doing business under the laws of the United States of America, any State thereof or the District of Columbia, authorized under such laws to act as Authenticating Agent, having a combined capital and surplus of not less than $50,000,000 and subject to supervision or examination by Federal or State authority. If such Authenticating Agent publishes reports of condition at least annually, pursuant to law or to the requirements of said supervising or examining authority, then for the purposes of this Section, the combined capital and surplus of such Authenticating Agent shall be deemed to be its combined capital and surplus as set forth in its most recent report of condition so published. If at any time an Authenticating Agent shall cease to be eligible in accordance with the provisions of this Section, such Authenticating Agent shall resign immediately in the manner and with the effect specified in this Section.

     Any corporation into which an Authenticating Agent may be merged or converted or with which it may be consolidated, or any corporation resulting from any merger, conversion or consolidation to which such Authenticating Agent shall be a party, or any corporation succeeding to all or substantially all of the corporate agency or corporate trust business of such Authenticating Agent, shall continue to be an Authenticating Agent, provided such corporation shall be otherwise eligible under this Section, without the execution or filing of any paper or any further act on the part of the Trustee or such Authenticating Agent.

     An Authenticating Agent may resign at any time by giving written notice thereof to the Trustee and to the Company. The Trustee may at any time terminate the agency of an Authenticating Agent by giving written notice thereof to such Authenticating Agent and to the Company. Upon receiving such a notice of resignation or upon such a termination, or in case at any time such Authenticating Agent shall cease to be eligible in accordance with the provisions of this

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Section, the Trustee may appoint a successor Authenticating Agent which shall be acceptable to the Company and shall mail written notice of such appointment by first-class mail, postage prepaid, to all Holders of Securities of the series with respect to which such Authenticating Agent will serve, as their names and addresses appear in the Security Register. Any successor Authenticating Agent upon acceptance of its appointment hereunder shall become vested with all the rights, powers and duties of its predecessor hereunder, with like effect as if originally named as an Authenticating Agent. No successor Authenticating Agent shall be appointed unless eligible under the provisions of this Section.

     Except with respect to an Authenticating Agent appointed at the request of the Company, the Trustee agrees to pay to each Authenticating Agent from time to time reasonable compensation for its services under this Section, and the Trustee shall be entitled to be reimbursed by the Company for such payments, subject to the provisions of Section 607.

     If an appointment with respect to one or more series is made pursuant to this Section, the Securities of such series may have endorsed thereon, in addition to the Trustee’s certificate of authentication, an alternative certificate of authentication in the following form:

     This is one of the Securities of the series designated therein referred to in the within-mentioned Indenture.

THE CHASE MANHATTAN BANK, As Trustee
By:
	As Authenticating Agent
By:
	Authorized Officer

ARTICLE SEVEN

HOLDERS LISTS AND REPORTS BY TRUSTEE AND COMPANY

SECTION 701. Company to Furnish Trustee Names and Addresses of Holders.

     The Company will furnish or cause to be furnished to the Trustee

          (1) semi-annually, not later than May 15 and November 15 in each year, a list for each series of Securities, in such form as the Trustee may reasonably require, of the names and

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addresses of the Holders of Securities of such series as of the preceding April 30 or October 31, as the case may be, and

          (2) at such other times as the Trustee may request in writing, within 30 days after the receipt by the Company of any such request, a list of similar form and content as of a date not more than 15 days prior to the time such list is furnished;

provided, however, that if and so long as the Trustee shall be the Security Registrar for Securities of a series, no such list need be furnished with respect to such series of Securities.

SECTION 702. Preservation of Information; Communications to Holders.

     The Trustee shall comply with the obligations imposed upon it pursuant to Section 312 of the Trust Indenture Act.

     The rights of the Holders to communicate with other Holders with respect to their rights under this Indenture or under the Securities, and the corresponding rights and privileges of the Trustee, shall be as provided by the Trust Indenture Act.

     Every Holder of Securities, by receiving and holding the same, agrees with the Company and the Trustee that neither the Company nor the Trustee nor any agent of either of them shall be held accountable by reason of any disclosure of information as to the names and addresses of Holders made pursuant to the Trust Indenture Act.

SECTION 703. Reports by Trustee.

     The Trustee shall transmit to Holders such reports concerning the Trustee and its actions under this Indenture as may be required pursuant to the Trust Indenture Act at the times and in the manner provided pursuant thereto.

     Reports so required to be transmitted at stated intervals of not more than 12 months shall be transmitted no later than July 15 in each calendar year with respect to the 12-month period ending on the previous May 15, commencing May 15, 1999.

     A copy of each such report shall, at the time of such transmission to Holders, be filed by the Trustee with each stock exchange upon which any Securities are listed, with the Commission and with the Company. The Company will notify the Trustee when any Securities are listed on any stock exchange.

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SECTION 704. Reports by Company.

     The Company shall:

          (1) file with the Trustee, within 15 days after the Company is required to file the same with the Commission, copies of the annual reports and of the information, documents and other reports (or copies of such portions of any of the foregoing as the Commission may from time to time by rules and regulations prescribe) which the Company may be required to file with the Commission pursuant to Section 13 or Section 15(d) of the Exchange Act; or, if the Company is not required to file information, documents or reports pursuant to either of said Sections, then it shall file with the Trustee and the Commission, in accordance with rules and regulations prescribed from time to time by the Commission, such of the supplementary and periodic information, documents and reports which may be required pursuant to Section 13 of the Exchange Act in respect of a security listed and registered on a national securities exchange as may be prescribed from time to time in such rules and regulations;

          (2) file with the Trustee and the Commission, in accordance with rules and regulations prescribed from time to time by the Commission, such additional information, documents and reports with respect to compliance by the Company with the conditions and covenants of this Indenture as may be required from time to time by such rules and regulations; and

          (3) transmit by mail to all Holders, as their names and addresses appear in the Security Register, within 30 days after the filing thereof with the Trustee, such summaries of any information, documents and reports required to be filed by the Company pursuant to paragraphs (1) and (2) of this Section as may be required by rules and regulations prescribed from time to time by the Commission.

ARTICLE EIGHT

CONSOLIDATION, MERGER, CONVEYANCE, TRANSFER OR LEASE

SECTION 801. Company May Consolidate, Etc., Only on Certain Terms.

     The Company shall not consolidate with or merge into any other Person or sell, lease or transfer its properties and assets as, or substantially as, an entirety to, any Person, unless:

          (1) (A) in the case of a merger, the Company is the surviving entity, or (B) the Person formed by such consolidation or into which the Company is merged or the Person which acquires by sale or transfer, or which leases, the properties and assets of the Company as, or substantially as, an entirety shall expressly assume, by an indenture supplemental hereto, executed and delivered to the Trustee, in form reasonably satisfactory to the Trustee, the due and punctual payment of the principal of and any premium and interest on all the Securities and the performance

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or observance of every covenant and condition of this Indenture on the part of the Company to be performed or observed;

          (2) immediately after giving effect to such transaction, no Default or Event of Default exists; and

          (3) the Company has delivered to the Trustee an Officer’s Certificate and an Opinion of Counsel, each stating that such consolidation, merger, sale, transfer or lease and the supplemental indenture required in connection with such transaction comply with this Article and that all conditions precedent herein provided for relating to such transaction have been complied with.

SECTION 802. Successor Substituted.

     Upon any consolidation of the Company with, or merger of the Company into, any other Person or any sale, transfer or lease of the properties and assets of the Company as, or substantially as, an entirety in accordance with Section 801, the successor Person formed by such consolidation or into which the Company is merged or to which such sale, transfer or lease is made shall succeed to, and be substituted for, and may exercise every right and power of, the Company under this Indenture with the same effect as if such successor Person had been named originally as the Company herein, and thereafter, except in the case of a lease, the predecessor Person shall be relieved of all obligations and covenants under this Indenture and the Securities.

ARTICLE NINE

SUPPLEMENTAL INDENTURES

SECTION 901. Supplemental Indentures Without Consent of Holders.

     Without the consent of any Holders, the Company and the Trustee, at any time and from time to time, may enter into one or more indentures supplemental hereto, in form satisfactory to the Trustee, for any of the following purposes:

          (1) to secure the Securities pursuant to the requirements of Section 1006 or otherwise; or

          (2) to evidence the succession of another Person to the Company and the assumption by any such successor of the covenants of the Company herein and in the Securities; or

          (3) to add to the covenants of the Company or the Events of Default for the benefit of the Holders of all or any series of Securities (and if such covenants or Events of Default are to be for the benefit of less than all series of Securities, stating that such covenants or Events of

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Default, as the case may be, are expressly being included solely for the benefit of such series) or to surrender any right or power herein conferred upon the Company; or

          (4) to add to, change or eliminate any of the provisions of this Indenture in respect of one or more series of Securities; provided, however, that any such addition, change or elimination shall become effective only when there is no Security Outstanding of any series created prior to the execution of such supplemental indenture which is entitled to the benefit of such provision; or

          (5) to establish the form or terms of securities of any series as permitted by Sections 201 and 301; or

          (6) to cure any ambiguity, to correct or supplement any provision herein which may be inconsistent with any other provision herein, to comply with any applicable mandatory provisions of law or to make any other provisions with respect to matters or questions arising under this Indenture, provided that such action pursuant to this Clause (6) shall not adversely affect the interests of the Holders of Securities of any series in any material respect; or

          (7) to evidence and provide for the acceptance of appointment hereunder by a successor Trustee with respect to the Securities of one or more series and to add to or change any of the provisions of this Indenture as shall be necessary to provide for or facilitate the administration of the trusts hereunder by more than one Trustee, pursuant to the requirements of Section 611; or

          (8) to modify, eliminate or add to the provisions of this Indenture to such extent as shall be necessary to effect the qualification of this Indenture under the Trust Indenture Act or under any similar federal statute subsequently enacted, and to add to this Indenture such other provisions as may be expressly required under the Trust Indenture Act.

SECTION 902. Supplemental Indentures with Consent of Holders.

     With the consent of the Holders of a majority in aggregate principal amount of the Outstanding Securities of all series affected by such supplemental indenture (voting as one class), by Act of said Holders delivered to the Company and the Trustee, the Company and the Trustee may enter into an indenture or indentures supplemental hereto for the purpose of adding any provisions to or changing in any manner or eliminating any of the provisions of this Indenture or of modifying in any manner the rights of the Holders of Securities of such series under this Indenture; provided, however, that no such supplemental indenture shall, without the consent of the Holder of each Outstanding Security affected thereby,

          (1) change the Stated Maturity of the principal of, or any installment of principal of or interest, if any, on, any Security, or reduce the principal amount thereof or premium, if any, on or the rate of interest thereon, or

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          (2) reduce the percentage in principal amount of the Outstanding Securities of any series, the consent of whose Holders is required for any such supplemental indenture, or the consent of whose Holders is required for any waiver (of compliance with certain provisions of this Indenture or certain defaults hereunder and their consequences) provided for in this Indenture, or

          (3) change any obligation of the Company, with respect to Outstanding Securities of a series, to maintain an office or agency in the places and for the purposes specified in Section 1002 for such series, or

          (4) modify any of the provisions of this Section, Section 513 or Section 1008, except to increase any such percentage or to provide that certain other provisions of this Indenture cannot be modified or waived without the consent of the Holder of each Outstanding Security affected thereby; provided, however, that this clause shall not be deemed to require the consent of any Holder with respect to changes in the references to “the Trustee” and concomitant changes in this Section, or the deletion of this proviso, in accordance with the requirements of Sections 611 and 901(7).

A supplemental indenture which changes or eliminates any covenant or other provision of this Indenture which has expressly been included solely for the benefit of one or more particular series of Securities, or which modifies the rights of the Holders of Securities of such series with respect to such covenant or other provision, shall be deemed not to affect the rights under this Indenture of the Holders of Securities of any other series.

     It shall not be necessary for any Act of Holders under this Section to approve the particular form of any proposed supplemental indenture, but it shall be sufficient if such Act shall approve the substance thereof.

SECTION 903. Execution of Supplemental Indentures.

     In executing, or accepting the additional trusts created by, any supplemental indenture permitted by this Article or the modifications thereby of the trusts created by this Indenture, the Trustee shall be entitled to receive, and (subject to Section 601) shall be fully protected in relying upon, an Opinion of Counsel stating that the execution of such supplemental indenture is authorized or permitted by this Indenture. The Trustee may, but shall not be obligated to, enter into any such supplemental indenture which affects the Trustee’s own rights, duties or immunities under this Indenture or otherwise.

SECTION 904. Effect of Supplemental Indentures.

     Upon the execution of any supplemental indenture under this Article, this Indenture shall be modified in accordance therewith, and such supplemental indenture shall form a part of this Indenture for all purposes; and every Holder of Securities theretofore or thereafter authenticated and delivered hereunder shall be bound thereby.

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SECTION 905. Conformity with Trust Indenture Act.

     Every supplemental indenture executed pursuant to this Article shall conform to the requirements of the Trust Indenture Act as then in effect.

SECTION 906. Reference in Securities to Supplemental Indentures.

     Securities of any series authenticated and delivered after the execution of any supplemental indenture pursuant to this Article may, and shall if required by the Trustee, bear a notation in form approved by the Trustee as to any matter provided for in such supplemental indenture. If the Company shall so determine, new Securities of any series so modified as to conform, in the opinion of the Trustee and the Company, to any such supplemental indenture may be prepared and executed by the Company and authenticated and delivered by the Trustee in exchange for Outstanding Securities of such series.

ARTICLE TEN

COVENANTS

SECTION 1001. Payment of Principal, Premium and Interest.

     The Company covenants and agrees for the benefit of each series of Securities that it will duly and punctually pay the principal of and any premium and interest on the Securities of that series in accordance with the terms of the Securities and this Indenture.

SECTION 1002. Maintenance of Office or Agency.

     The Company will maintain in each Place of Payment for any series of Securities an office or agency where Securities of that series may be presented or surrendered for payment, where Securities of that series may be surrendered for registration of transfer or exchange and where notices and demands to or upon the Company in respect of the Securities of that series and this Indenture may be served. The Company will give prompt written notice to the Trustee of the location, and any change in the location, of such office or agency. If at any time the Company shall fail to maintain any such required office or agency or shall fail to furnish the Trustee with the address thereof, such presentations, surrenders, notices and demands may be made or served at the Corporate Trust Office of the Trustee, and the Company hereby appoints the Trustee as its agent to receive all such presentations, surrenders, notices and demands.

     The Company may also from time to time designate one or more other offices or agencies where the Securities of one or more series may be presented or surrendered for any or all such purposes and may from time to time rescind such designations; provided, however, that no such designation or rescission shall in any manner relieve the Company of its obligation to maintain an office or agency in each Place of Payment for Securities of any series for such purposes. The

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Company will give prompt written notice to the Trustee of any such designation or rescission and of any change in the location of any such other office or agency.

     Except as otherwise specified with respect to a series of Securities as contemplated by Section 301, the Company hereby initially designates as the Place of Payment for each series of Securities The City and State of New York, and initially appoints the Trustee at its Corporate Trust Office as the Company’s office or agency for each such purpose in such city.

SECTION 1003. Money for Securities Payments to Be Held in Trust.

     If the Company shall at any time act as its own Paying Agent with respect to any series of Securities, it will, on or before each due date of the principal of or any premium or interest on any of the Securities of that series, segregate and hold in trust for the benefit of the Persons entitled thereto a sum sufficient to pay the principal and any premium and interest so becoming due until such sums shall be paid to such Persons or otherwise disposed of as herein provided and will promptly notify the Trustee of its action or failure so to act.

     Whenever the Company shall have one or more Paying Agents for any series of Securities, it will, on or prior to each due date of the principal of or any premium or interest on any Securities of that series, deposit with a Paying Agent a sum sufficient to pay such amount, such sum to be held as provided by the Trust Indenture Act, and (unless such Paying Agent is the Trustee) the Company will promptly notify the Trustee of its action or failure so to act.

     The Company will cause each Paying Agent for any series of Securities other than the Trustee to execute and deliver to the Trustee an instrument in which such Paying Agent shall agree with the Trustee, subject to the provisions of this Section, that such Paying Agent will (1) hold all sums held by it for the payment of the principal of (and premium, if any) or interest, if any, on Securities of that series in trust for the benefit of the Persons entitled thereto until such sums shall be paid to such Persons or otherwise disposed of as herein provided; (2) give the Trustee notice of any default by the Company (or any other obligor upon the Securities of that series) in the making of any payment of principal (and premium, if any) or interest if any, on the Securities of that series; and (3) during the continuance of any such default, upon the written request of the Trustee, forthwith pay to the Trustee all sums held in trust by such Paying Agent for payment in respect of the Securities of that series.

     The Company may at any time, for the purpose of obtaining the satisfaction and discharge of this Indenture or for any other purpose, pay, or by Company Order direct any Paying Agent to pay, to the Trustee all sums held in trust by the Company or such Paying Agent, such sums to be held by the Trustee upon the same trusts as those upon which such sums were held by the Company or such Paying Agent; and, upon such payment by any Paying Agent to the Trustee, such Paying Agent shall be released from all further liability with respect to such money.

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     Any money deposited with the Trustee or any Paying Agent, or then held by the Company, in trust for the payment of the principal of or any premium or interest on any Security of any series and remaining unclaimed for two years after such principal, premium or interest has become due and payable shall be paid to the Company on Company Request, or (if then held by the Company) shall be discharged from such trust; and the Holder of such Security shall thereafter, as an unsecured general creditor, look only to the Company for payment thereof, and all liability of the Trustee or such Paying Agent with respect to such trust money, and all liability of the Company as trustee thereof, shall thereupon cease; provided, however, that the Trustee or such Paying Agent, before being required to make any such repayment, may at the expense of the Company cause to be published once, in an Authorized Newspaper in each Place of Payment with respect to such series, notice that such money remains unclaimed and that, after a date specified therein, which shall not be less than 30 days from the date of such publication, any unclaimed balance of such money then remaining will be repaid to the Company.

SECTION 1004. Statement by Officers as to Default.

     The Company will deliver to the Trustee, within 150 days after the end of each fiscal year of the Company ending after the date hereof, an Officer’s Certificate, stating whether or not to the best knowledge of the signer thereof the Company is in default in the performance and observance of any of the terms, provisions and conditions of this Indenture (without regard to any period of grace or requirement of notice provided hereunder) and, if the Company shall be in default, specifying all such defaults and the nature and status thereof of which they may have knowledge.

SECTION 1005. Existence.

     Subject to Article Eight, the Company will do or cause to be done all things necessary to preserve and keep in full force and effect its existence, rights (charter and statutory) and franchises; provided, however, that the Company shall not be required to preserve any such right or franchise if it shall determine that the preservation thereof is no longer desirable in the conduct of the business of the Company.

Section 1006. Limitations on Liens.

     The Company will not, nor will it permit any Restricted Subsidiary to, create, assume, incur or suffer to exist any Lien upon any Principal Property, whether owned or leased on the date of this Indenture or thereafter acquired, to secure any Debt of the Company or any other Person (other than the Securities issued hereunder), without in any such case making effective provision whereby all of the Securities Outstanding hereunder shall be secured equally and ratably with, or prior to, such Debt so long as such Debt shall be so secured. This restriction shall not apply to:

               (i) any Lien upon any property or assets of the Company or any Restricted Subsidiary in existence on the date of this Indenture or created pursuant to an “after-acquired property” clause or similar term in existence on the date of this Indenture or

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any mortgage, pledge agreement, security agreement or other similar instrument in existence on the date of this Indenture;

               (ii) any Lien upon any property or assets created at the time of acquisition of such property or assets by the Company or any Restricted Subsidiary or within one year after such time to secure all or a portion of the purchase price for such property or assets or Debt incurred to finance such purchase price, whether such Debt was incurred prior to, at the time of or within one year of such acquisition;

               (iii) any Lien upon any property or assets existing thereon at the time of the acquisition thereof by the Company or any Restricted Subsidiary (whether or not the obligations secured thereby are assumed by the Company or any Restricted Subsidiary);

               (iv) any Lien upon any property or assets of a Person existing thereon at the time such Person becomes a Restricted Subsidiary by acquisition, merger or otherwise;

               (v) the assumption by the Company or any Restricted Subsidiary of obligations secured by any Lien existing at the time of the acquisition by the Company or any Restricted Subsidiary of the property or assets subject to such Lien or at the time of the acquisition of the Person which owns such property or assets;

               (vi) any Lien on property to secure all or part of the cost of construction or improvements thereon or to secure Debt incurred prior to, at the time of, or within one year after completion of such construction or making of such improvements, to provide funds for any such purpose;

               (vii) any Lien on any oil, gas, mineral and processing and other plant properties to secure the payment of costs, expenses or liabilities incurred under any lease or grant or operating or other similar agreement in connection with or incident to the exploration, development, maintenance or operation of such properties;

               (viii) any Lien arising from or in connection with a conveyance by the Company or any Restricted Subsidiary of any production payment with respect to oil, gas, natural gas, carbon dioxide, sulphur, helium, coal, metals, minerals, steam, timber or other natural resources;

               (ix) any Lien in favor of the Company or any Restricted Subsidiary;

               (x) any Lien created or assumed by the Company or any Restricted Subsidiary in connection with the issuance of Debt the interest on which is excludable from gross income of the holder of such Debt pursuant to the Internal Revenue Code of 1986, as amended, or any successor statute, for the purpose of financing, in whole or in part, the

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acquisition or construction of property or assets to be used by the Company or any Subsidiary;

               (xi) any Lien upon property or assets of any foreign Restricted Subsidiary to secure Debt of that foreign Restricted Subsidiary;

               (xii) Permitted Liens;

               (xiii) any Lien upon any additions, improvements, replacements, repairs, fixtures, appurtenances or component parts thereof attaching to or required to be attached to property or assets pursuant to the terms of any mortgage, pledge agreement, security agreement or other similar instrument, creating a Lien upon such property or assets permitted by Clauses (i) through (xii), inclusive, of this Section; or

               (xiv) any extension, renewal, refinancing, refunding or replacement (or successive extensions, renewals, refinancing, refundings or replacements) of any Lien, in whole or in part, that is referred to in Clauses (i) through (xiii), inclusive, of this Section, or of any Debt secured thereby; provided, however, that the principal amount of Debt secured thereby shall not exceed the greater of the principal amount of Debt so secured at the time of such extension, renewal, refinancing, refunding or replacement and the original principal amount of Debt so secured (plus in each case the aggregate amount of premiums, other payments, costs and expenses required to be paid or incurred in connection with such extension, renewal, refinancing, refunding or replacement); provided, further, however, that such extension, renewal, refinancing, refunding or replacement shall be limited to all or a part of the property (including improvements, alterations and repairs on such property) subject to the encumbrance so extended, renewed, refinanced, refunded or replaced (plus improvements, alterations and repairs on such property).

     Notwithstanding the foregoing provisions of this Section, the Company may, and may permit any Restricted Subsidiary to, create, assume, incur or suffer to exist any Lien upon any Principal Property to secure any Debt of the Company or any other Person (other than the Securities) that is not excepted by Clauses (i) through (xiv), inclusive, of this Section without securing the Securities issued hereunder, provided that the aggregate principal amount of all Debt then outstanding secured by such Lien and all similar Liens, together with all net sale proceeds from Sale-Leaseback Transactions (excluding Sale-Leaseback Transactions permitted by Clauses (i) through (iv), inclusive, of Section 1007), does not exceed 15% of Consolidated Net Tangible Assets.

SECTION 1007. Restriction of Sale-Leaseback Transaction.

     The Company will not, nor will it permit any Restricted Subsidiary to, engage in a Sale-Leaseback Transaction unless:

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               (i) such Sale-Leaseback Transaction occurs within one year from the date of acquisition of the Principal Property subject thereto or the date of the completion of construction or commencement of full operations on such Principal Property, whichever is later;

               (ii) the Sale-Leaseback Transaction involves a lease for a period, including renewals, of not more than three years;

               (iii) the Company or such Restricted Subsidiary would be entitled to incur Debt secured by a Lien on the Principal Property subject thereto in a principal amount equal to or exceeding the net sale proceeds from such Sale-Leaseback Transaction without securing the Securities; or

               (iv) the Company or such Restricted Subsidiary, within a one-year period after such Sale-Leaseback Transaction, applies or causes to be applied an amount not less than the net sale proceeds from such Sale-Leaseback Transaction to (A) the repayment, redemption or retirement of Funded Debt of the Company or any Subsidiary, or (B) investment in another Principal Property.

     Notwithstanding the foregoing provisions of this Section, the Company may, and may permit any Restricted Subsidiary to, effect any Sale-Leaseback Transaction that is not excepted by Clauses (i) through (iv), inclusive, of this Section, provided that the net sale proceeds from such Sale-Leaseback Transaction, together with the aggregate principal amount of then outstanding Debt (other than the Securities) secured by Liens upon Principal Properties not excepted by Clauses (i) through (xiv), inclusive, of Section 1006, do not exceed 15% of the Consolidated Net Tangible Assets.

SECTION 1008. Waiver of Certain Covenants.

     The Company may omit in any particular instance to comply with any term, provision or condition set forth in Section 1005, 1006 or 1007 with respect to the Securities of any series if before the time for such compliance the Holders of at least a majority in aggregate principal amount of the Outstanding Securities of all affected series (voting as one class) shall, by Act of such Holders, either waive such compliance in such instance or generally waive compliance with such term, provision or condition, but no such waiver shall extend to or affect such term, provision or condition except to the extent so expressly waived, and, until such waiver shall become effective, the obligations of the Company and the duties of the Trustee in respect of any such term, provision or condition shall remain in full force and effect.

     A waiver which changes or eliminates any term, provision or condition of this Indenture which has expressly been included solely for the benefit of one or more particular series of Securities, or which modifies the rights of the Holders of Securities of such series with respect to such term, provision or condition, shall be deemed not to affect the rights under this Indenture of the Holders of Securities of any other series.

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ARTICLE ELEVEN

REDEMPTION OF SECURITIES

SECTION 1101. Applicability of Article.

     Securities of any series which are redeemable before their Stated Maturity shall be redeemable in accordance with their terms and (except as otherwise specified as contemplated by Section 301 for Securities of any series) in accordance with this Article.

SECTION 1102. Election to Redeem; Notice to Trustee.

     The election of the Company to redeem any Securities shall be evidenced by a Board Resolution. In case of any redemption at the election of the Company of less than all the Securities of any series, the Company shall, at least 45 days prior to the Redemption Date fixed by the Company (unless a shorter notice shall be satisfactory to the Trustee), notify the Trustee of such Redemption Date, of the principal amount of Securities of such series to be redeemed and, if applicable, of the tenor of the Securities to be redeemed. In the case of any redemption of Securities (1) prior to the expiration of any restriction on such redemption provided in the terms of such Securities or elsewhere in this Indenture, or (2) pursuant to an election of the Company which is subject to a condition specified in the terms of such Securities, the Company shall furnish the Trustee with an Officer’s Certificate evidencing compliance with such restriction or condition.

SECTION 1103. Selection by Trustee of Securities to be Redeemed.

     If less than all the Securities of any series are to be redeemed (unless all the Securities of such series and of a specified tenor are to be redeemed), the particular Securities to be redeemed shall be selected not more than 45 days prior to the Redemption Date by the Trustee, from the outstanding Securities of such series not previously called for redemption, by such method as the Trustee shall deem fair and appropriate and which may provide for the selection for redemption of portions (equal to the minimum authorized denomination for Securities of that series or any integral multiple thereof) of the principal amount of Securities of such series of a denomination larger than the minimum authorized denomination for Securities of that series.

     The Trustee shall promptly notify the Company in writing of the Securities selected for redemption and, in the case of any Securities selected for partial redemption, the principal amount thereof to be redeemed.

     For all purposes of this Indenture, unless the context otherwise requires, all provisions relating to the redemption of Securities shall relate, in the case of any Securities redeemed or to be redeemed only in part, to the portion of the principal amount of such Securities which has been or is to be redeemed.

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SECTION 1104. Notice of Redemption.

     Notice of redemption shall be given by first-class mail (if international mail, by air mail), postage prepaid, mailed not less than 30 nor more than 60 days prior to the Redemption Date, to each Holder of Securities to be redeemed, at his address appearing in the Security Register.

     All notices of redemption shall state:

          (1) the Redemption Date,

          (2) the Redemption Price,

          (3) if less than all the Outstanding Securities of any series and of a specified tenor are to be redeemed, the identification (and, in the case of partial redemption of any Securities, the principal amounts) of the particular Securities to be redeemed,

          (4) that on the Redemption Date the Redemption Price will become due and payable upon each such Security to be redeemed and, if applicable, that interest thereon will cease to accrue on and after said date,

          (5) the place or places where such Securities are to be surrendered for payment of the Redemption Price, and

          (6) that the redemption is for a sinking fund, if such is the case.

     Notice of redemption of Securities to be redeemed shall be given by the Company or, at the Company’s request, by the Trustee in the name and at the expense of the Company.

SECTION 1105. Deposit of Redemption Price.

     On or prior to any Redemption Date, the Company shall deposit with the Trustee or with a Paying Agent (or, if the Company is acting as its own Paying Agent, segregate and hold in trust as provided in Section 1003) an amount of money sufficient to pay the Redemption Price of, and (except if the Redemption Date shall be an Interest Payment Date) accrued interest on, all the Securities which are to be redeemed on that date.

SECTION 1106. Securities Payable on Redemption Date.

     Notice of redemption having been given as aforesaid, the Securities so to be redeemed shall, on the Redemption Date, become due and payable at the Redemption Price therein specified, and from and after such date (unless the Company shall default in the payment of the Redemption Price and accrued interest) such Securities shall cease to bear interest. Upon surrender of any such Security for redemption in accordance with said notice, such Security shall be paid by the Company

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at the Redemption Price, together with accrued interest to the Redemption Date; provided, however, that, unless otherwise specified as contemplated by Section 301, installments of interest whose Stated Maturity is on or prior to the Redemption Date shall be payable to the Holders of such Securities, or one or more Predecessor Securities, registered as such at the close of business on the relevant Record Dates according to their terms and the provisions of Section 307.

     If any Security called for redemption shall not be so paid upon surrender thereof for redemption, the principal and any premium shall, until paid, bear interest from the Redemption Date at the rate prescribed therefor in the Security.

SECTION 1107. Securities Redeemed in Part.

     Any Security which is to be redeemed only in part shall be surrendered at a Place of Payment therefor (with, if the Company or the Trustee so requires, due endorsement by, or a written instrument of transfer in form satisfactory to the Company and the Trustee duly executed by, the Holder thereof or his attorney duly authorized in writing), and the Company shall execute, and the Trustee shall authenticate and deliver to the Holder of such Security without service charge, a new Security or Securities of the same series and of like tenor, of any authorized denomination as requested by such Holder, in aggregate principal amount equal to and in exchange for the unredeemed portion of the principal of the Security so surrendered.

ARTICLE TWELVE

SINKING FUNDS

SECTION 1201. Applicability of Article.

     The provisions of this Article shall be applicable to any sinking fund for the retirement of Securities of a series except as otherwise specified as contemplated by Section 301 for Securities of such series.

     The minimum amount of any sinking fund payment provided for by the terms of Securities of any series is herein referred to as a “mandatory sinking fund payment”, and any payment in excess of such minimum amount provided for by the terms of Securities of any series is herein referred to as an “optional sinking fund payment”. If provided for by the terms of Securities of any series, the cash amount of any sinking fund payment may be subject to reduction as provided in Section 1202. Each sinking fund payment shall be applied to the redemption of Securities of any series as provided for by the terms of Securities of such series.

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SECTION 1202. Satisfaction of Sinking Fund Payments with Securities.

     The Company (1) may deliver Outstanding Securities of a series (other than any previously called for redemption), and (2) may apply as a credit Securities of a series which have been redeemed either at the election of the Company pursuant to the terms of such Securities or through the application of permitted optional sinking fund payments pursuant to the terms of such Securities, in each case in satisfaction of all or any part of any sinking fund payment with respect to the Securities of such series required to be made pursuant to the terms of such Securities as provided for by the terms of such series; provided that such Securities have not been previously so credited. Such Securities shall be received and credited for such purpose by the Trustee at the Redemption Price specified in such Securities for redemption through operation of the sinking fund and the amount of such sinking fund payment shall be reduced accordingly.

SECTION 1203. Redemption of Securities for Sinking Fund.

     Not less than 45 days prior to each sinking fund payment date for any series of Securities (unless a shorter period shall be satisfactory to the Trustee), the Company will deliver to the Trustee an Officer’s Certificate specifying the amount of the next ensuing sinking fund payment for that series pursuant to the terms of that series, the portion thereof, if any, which is to be satisfied by payment of cash and the portion thereof, if any, which is to be satisfied by delivering and crediting Securities of that series pursuant to Section 1202 and stating the basis for such credit and that such Securities have not been previously so credited, and will also deliver to the Trustee any Securities to be so delivered. Not less than 30 days before each such sinking fund payment date the Trustee shall select the Securities to be redeemed upon such sinking fund payment date in the manner specified in Section 1103 and cause notice of the redemption thereof to be given in the name of and at the expense of the Company in the manner provided in Section 1104. Such notice having been duly given, the redemption of such Securities shall be made upon the terms and in the manner stated in Sections 1106 and 1107.

ARTICLE THIRTEEN

DEFEASANCE

SECTION 1301. Applicability of Article.

     The provisions of this Article shall be applicable to each series of Securities except as otherwise specified as contemplated by Section 301 for Securities of such series.

SECTION 1302. Legal Defeasance.

     In addition to discharge of the Indenture pursuant to Section 401, the Company shall be deemed to have paid and discharged the entire indebtedness on all the Securities of such a series on the 91st day after the date of the deposit referred to in Clause (1) below, and the provisions of this

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Indenture with respect to the Securities of such series shall no longer be in effect (except as to (i) rights of registration of transfer and exchange of Securities of such series and the Company’s right of optional redemption, if any, (ii) substitution of mutilated, destroyed, lost or stolen Securities, (iii) rights of holders of Securities to receive payments of principal thereof and interest thereon, upon the original stated due dates therefor or on the specified redemption dates therefor (but not upon acceleration), and remaining rights of the holders to receive mandatory sinking fund payments, if any, (iv) the rights, obligations, duties and immunities of the Trustee hereunder, (v) the rights of the holders of Securities of such series as beneficiaries hereof with respect to the property so deposited with the Trustee payable to all or any of them, and (vi) the obligations of the Company under Section 1002), and the Trustee, at the expense of the Company, shall, upon a Company Request, execute proper instruments acknowledging the same, if the conditions set forth below are satisfied (hereinafter, “defeasance”):

          (1) The Company has irrevocably deposited or caused to be deposited with the Trustee as trust funds in trust, for the purposes of making the following payments, specifically pledged as security for, and dedicated solely to, the benefit of the Holders of the Securities of such series (i) cash in an amount, or (ii) in the case of any series of Securities the payments on which may only be made in legal coin or currency of the United States, U.S. Government Obligations, maturing as to principal and interest at such times and in such amounts as will insure the availability of cash, or (iii) a combination thereof, sufficient, in the opinion of a nationally recognized firm of independent public accountants expressed in a written certification thereof delivered to the Trustee, to pay (A) the principal and interest and premium, if any, on all Securities of such series on each date that such principal, interest or premium, if any, is due and payable or on any Redemption Date established pursuant to Clause (3) below, and (B) any mandatory sinking fund payments on the dates on which such payments are due and payable in accordance with the terms of the Indenture and the Securities of such series;

          (2) The Company has delivered to the Trustee an Opinion of Counsel based on the fact that (x) the Company has received from, or there has been published by, the Internal Revenue Service a ruling, or (y) since the date hereof, there has been a change in the applicable federal income tax law, in either case to the effect that, and such opinion shall confirm that, the holders of the Securities of such series will not recognize income, gain or loss for federal income tax purposes as a result of such deposit and defeasance and will be subject to federal income tax on the same amount and in the same manner and at the same times, as would have been the case if such deposit and defeasance had not occurred;

          (3) If the Securities are to be redeemed prior to Stated Maturity (other than from mandatory sinking fund payments or analogous payments), notice of such redemption shall have been duly given pursuant to this Indenture or provision therefor satisfactory to the Trustee shall have been made;

          (4) No Event of Default or event which with notice or lapse of time or both would become an Event of Default shall have occurred and be continuing on the date of such deposit; and

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          (5) The Company has delivered to the Trustee an Officer’s Certificate and an Opinion of Counsel, each stating that all conditions precedent provided for relating to the defeasance contemplated by this provision have been complied with.

     For this purpose, such defeasance means that the Company and any other obligor upon the Securities of such series shall be deemed to have paid and discharged the entire debt represented by the Securities of such series, which shall thereafter be deemed to be “Outstanding” only for the purposes of Section 1304 and the rights and obligations referred to in Clauses (i) through (vi), inclusive, of the first paragraph of this Section, and to have satisfied all its other obligations under the Securities of such series and this Indenture insofar as the Securities of such series are concerned.

SECTION 1303. Covenant Defeasance.

     The Company and any other obligor, if any, shall be released on the 91st day after the date of the deposit referred to in Clause (1) below from its obligations under Sections 704, 801, 1005, 1006 and 1007 with respect to the Securities of any series on and after the date the conditions set forth below are satisfied (hereinafter, “covenant defeasance”), and the Securities of such series shall thereafter be deemed to be not “Outstanding” for the purposes of any request, demand, authorization, direction, notice, waiver, consent or declaration or other action or Act of Holders (and the consequences of any thereof) in connection with such covenants, but shall continue to be deemed Outstanding for all other purposes hereunder. For this purpose, such covenant defeasance means that, with respect to the Securities of such series, the Company may omit to comply with and shall have no liability in respect of any term, condition or limitation set forth in any such Section, whether directly or indirectly by reason of any reference elsewhere herein to such Section or by reason of any reference in such Section to any other provision herein or in any other document and such omission to comply shall not constitute a Default or an Event of Default under Section 501, but, except as specified above, the remainder of this Indenture and the Securities of such series shall be unaffected thereby. The following shall be the conditions to application of this Section 1303:

          (1) The Company has irrevocably deposited or caused to be deposited with the Trustee as trust funds in trust for the purpose of making the following payments, specifically pledged as security for, and dedicated solely to, the benefit of the Holders of the Securities of such series, (i) cash in an amount, or (ii) in the case of any series of Securities the payments on which may only be made in legal coin or currency of the United States, U.S. Government Obligations, maturing as to principal and interest at such times and in such amounts as will insure the availability of cash, or (iii) a combination thereof, sufficient, in the opinion of a nationally recognized firm of independent public accountants expressed in a written certification thereof delivered to the Trustee, to pay (A) the principal and interest and premium, if any, on all Securities of such series on each date that such principal, interest or premium, if any, is due and payable or on any Redemption Date established pursuant to Clause (2) below, and (B) any mandatory sinking fund payments on the day on which such payments are due and payable in accordance with the terms of the Indenture and the Securities of such series;

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          (2) If the Securities are to be redeemed prior to Stated Maturity (other than from mandatory sinking fund payments or analogous payments), notice of such redemption shall have been duly given pursuant to this Indenture or provision therefor satisfactory to the Trustee shall have been made;

          (3) No Event of Default or event which with notice or lapse of time or both would become an Event of Default shall have occurred and be continuing on the date of such deposit;

          (4) The Company shall have delivered to the Trustee an Opinion of Counsel which shall confirm that the holders of the Securities of such series will not recognize income, gain or loss for federal income tax purposes as a result of such deposit and covenant defeasance and will be subject to federal income tax on the same amount and in the same manner and at the same times, as would have been the case if such deposit and covenant defeasance had not occurred; and

          (5) The Company shall have delivered to the Trustee an Officer’s Certificate stating that all conditions precedent provided for relating to the covenant defeasance contemplated by this provision have been complied with.

SECTION 1304. Application by Trustee of Funds Deposited for Payment of Securities.

     Subject to the provisions of the last paragraph of Section 1003, all moneys or U.S. Government Obligations deposited with the Trustee pursuant to Section 1302 or 1303 (and all funds earned on such moneys or U.S. Government Obligations) shall be held in trust and applied by it to the payment, either directly or through any Paying Agent (including the Company acting as its own Paying Agent), to the Holders of the particular Securities of such series for the payment or redemption of which such moneys have been deposited with the Trustee, of all sums due and to become due thereon for principal and interest; but such money need not be segregated from other funds except to the extent required by law. Subject to Sections 1302 and 1303, the Trustee promptly shall pay to the Company upon request any excess moneys held by them at any time.

SECTION 1305. Repayment to Company.

     The Trustee and any Paying Agent promptly shall pay or return to the Company upon Company Request any money and U.S. Government Obligations held by them at any time that are not required for the payment of the principal of and any interest on the Securities of any series for which money or U.S. Government Obligations have been deposited pursuant to Section 1302 or 1303.

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     The provisions of the last paragraph of Section 1003 shall apply to any money held by the Trustee or any Paying Agent under this Article that remains unclaimed for two years after the Maturity of any series of Securities for which money or U.S. Government obligations have been deposited pursuant to Section 1302 or 1303.

     This instrument may be executed with counterpart signature pages or in any number of counterparts, each of which so executed shall be deemed to be an original, but all such counterparts shall together constitute but one and the same instrument.

     IN WITNESS WHEREOF, the parties hereto have caused this Indenture to be duly executed, all as of the day and year first above written.

EL PASO ENERGY CORPORATION
By:	/s/ H. Brent Austin
Name: Title:	H. Brent Austin Executive Vice President and
	Chief Financial Officer
THE CHASE MANHATTAN BANK
By:	/s/ Richard Lorenzen
Name:	Richard Lorenzen
Title:	Assistant Vice President

Created by 10KWizard Technology      www.10KWizard.com

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EX-10.G

EXHIBIT 10.G

EL PASO ENERGY CORPORATION

STOCK OPTION PLAN FOR
NON-EMPLOYEE DIRECTORS

AMENDED AND RESTATED EFFECTIVE AS OF JANUARY 20, 1999

2

TABLE OF CONTENTS

SECTION 1	PURPOSE	1
SECTION 2	SHARES SUBJECT TO THE PLAN	1
SECTION 3	ADMINISTRATION OF THE PLAN	1
SECTION 4	PARTICIPATION IN THE PLAN	2
SECTION 5	STOCK OPTION GRANTS AND TERMS	2
SECTION 6	GENERAL PROVISIONS	5
SECTION 7	EFFECTIVE DATE AND DURATION OF PLAN	6
SECTION 8	COMPLIANCE WITH SECTION 16	6
SECTION 9	AMENDMENT, TERMINATION OR DISCONTINUANCE OF THE PLAN	6

El Paso Energy Corporation
Stock Option Plan For Non-Employee Directors Table of Contents

EL PASO ENERGY CORPORATION
STOCK OPTION PLAN FOR NON-EMPLOYEE DIRECTORS
AMENDED AND RESTATED EFFECTIVE AS OF JANUARY 20, 1999

SECTION 1 PURPOSE

     The purpose of the E1 Paso Energy Corporation Stock Option Plan for Non-Employee Directors, Amended and Restated effective as of January 20, 1999 (the “Plan”) is to attract and retain the services of experienced and knowledgeable non-employee Directors of E1 Paso Energy Corporation (the “Company”), and to provide an incentive for such Directors to increase their proprietary interests in the Company’s long-term success and progress.

SECTION 2 SHARES SUBJECT TO THE PLAN

     2.1 Subject to Section 2.2, the maximum number of shares of common stock of the Company, par value $3.00 per share, (the “Common Stock”) for which stock options may be granted under the Plan is two hundred thousand (200,000) (the “Shares”). The Shares shall be shares held in the Company’s treasury or out of authorized but unissued shares of the Company, or partly out of each, as shall be determined by the Plan Administrator (defined below), subject to, and reduced by (on a post-split basis), the number of shares of Common Stock awarded prior to the occurrence of a two-for-one stock split effected by the Company in the form of a 100% stock dividend on April 1, 1998.

     2.2 In the event of a recapitalization, stock split, stock dividend, exchange of shares, merger, reorganization, change in corporate structure or shares of the Company or similar event, the Board of Directors of the Company (the “Board”), may make appropriate adjustments in the number of Shares authorized for the Plan and, with respect to outstanding stock options, the Plan Administrator may make appropriate adjustments in the number of shares and the option price. In the event of any adjustment in the number of Shares covered by any stock option, any fractional Shares resulting from such adjustment shall be disregarded and each such stock option shall cover only the number of full Shares resulting from such adjustment.

SECTION 3 ADMINISTRATION OF THE PLAN

     Unless otherwise determined by the Board and subject to Section 9, the Plan shall be administered by a management committee (the “Plan Administrator”)consisting of the

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Stock Option Plan For Non-Employee Directors Page 1

Chairman of the Board of the Company and such other senior officers as the Chairman of the Board shall designate. The Plan Administrator shall interpret the Plan, shall prescribe, amend and rescind rules relating to the Plan from time to time as it deems proper and in the best interests of the Company, and shall take any other action necessary for the administration of the Plan.

SECTION 4 PARTICIPATION IN THE PLAN

     Each member of the Board elected or appointed who is not otherwise an employee of the Company or any subsidiary corporation (a “Participant”) shall be eligible to receive stock option grants as provided in the Plan.

SECTION 5 STOCK OPTION GRANTS AND TERMS

     Each stock option granted to a Participant under the Plan and the issuance of Shares thereunder shall be subject to the following terms:

5.1   OPTION GRANTS

     A Participant shall automatically receive (a) a grant of stock options to purchase three thousand (3,000) Shares when the Participant is initially elected or appointed as a Director of the Company and (b) a grant of stock options to purchase two thousand (2,000) Shares on each date the Participant is reelected as a Director of the Company at the annual meeting of stockholders of the Company, beginning with such annual meeting in 1998.

     Each stock option granted under the Plan shall be evidenced by a written instrument delivered by or on behalf of the Plan Administrator
containing terms, provisions and conditions not inconsistent with the Plan.

5.2   VESTING OF OPTIONS

     Each stock option granted to a Participant under the Plan shall be fully vested and immediately exercisable upon grant.

5.3   OPTION PRICE

     The option price for a stock option granted under the Plan shall be the fair market value of the Shares covered by the stock option at the time the stock option is granted to the Participant. For purposes of the Plan, “fair market value” shall be the mean between the highest and lowest quoted selling prices at which the Common Stock was sold on

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Stock Option Plan For Non-Employee Directors Page 2

such date as reported in the NYSE Composite Transactions by The Wall Street Journal for such date or, if no Common Stock was traded on such date, on the next preceding date on which Common Stock was so traded.

5.4   TIME AND MANNER OF EXERCISE OF A STOCK OPTION

     Each option may be exercised in whole or in part at any time and from time to time; provided, however, that no fewer than one hundred (100) Shares (or the remaining Shares then purchasable under the stock option, if less than one hundred (100) Shares) may be purchased upon exercise of any stock option hereunder and that only whole Shares will be issued pursuant to the exercise of any stock option.

     The purchase price of shares purchased under stock options shall be paid in full to the Company incident to the exercise of the stock option by delivery of consideration equal to the product of the option price and the number of shares purchased (the “Purchase Price”). Such consideration may be paid (i) in cash or by check; (ii) in shares of Common Stock already owned by the Participant for a sufficient time (generally six (6) months) to not result in an accounting charge to the Company, or any combination of cash and Common Stock, with the fair market value of such Common Stock valued as of the day prior to delivery; or (iii) by delivery of a properly executed exercise notice, together with irrevocable instructions to a broker to promptly deliver to the Company the amount of sale or loan proceeds to pay the Purchase Price. The Plan Administrator can specify that stock options granted or to be granted shall permit additional techniques to pay the Purchase Price. A Participant shall have none of the rights of a stockholder until the Shares of Common Stock are issued to the Participant.

5.5   TERM OF OPTIONS

     Each stock option shall expire ten (10) years from the date of the granting thereof, but shall be subject to earlier termination as follows:

(a)

In the event that a Participant ceases to be a Director of the Company for any reason other than the death of the Participant, the stock options granted to such Participant shall expire unless exercised by him or her within thirty-six (36) months after the date such Participant ceases to be a Director of the Company.

(b)

In the event of the death of a Participant, whether during the Participant’s service as a Director or during the thirty-six (36) month period referred to in Section 5.5(a), the stock options granted to such Participant shall be exercisable, and such stock options shall expire unless exercised within twelve (12) months after the date of the Participant’s death, by the legal representatives or the estate of such Participant, by any person or persons

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Stock Option Plan For Non-Employee Directors Page 3

whom the Participant shall have designated in writing on forms prescribed by and filed with the Company or, if no such designation has been made, by the person or persons to whom the Participant’s rights have passed by will or the laws of descent and distribution.

5.6   TRANSFERABILITY

     Stock options granted under the Plan and the rights and privileges conferred thereby shall not be subject to execution, attachment or similar process and may not be transferred, assigned, pledged or hypothecated in any manner (whether by operation of law or otherwise) other than by will or the applicable laws of descent and distribution. Notwithstanding the foregoing and only as provided by the Plan Administrator or the Company, as applicable, stock options may be transferred to a Participant’s immediate family members, directly or indirectly or by means of a trust, corporate entity or partnership (a person who thus acquires this option by such transfer, a “Permitted Transferee”). A transfer of a stock option may only be effected by the Company at the request of the Participant and shall become effective upon the Permitted Transferee agreeing to such terms as the Plan Administrator may require and only when recorded in the Company’s record of outstanding stock options. In the event a stock option is transferred as contemplated hereby, the stock option may not be subsequently transferred by the Permitted Transferee except a transfer back to the Participant or by will or the laws of descent and distribution. A transferred stock option may be exercised by a Permitted Transferee to the same extent as, and subject to the same terms and conditions as, the Participant (except as otherwise provided herein), as if no transfer had taken place. As used herein, “immediate family” shall mean, with respect to any person, such person’s child, stepchild, grandchild, parent, stepparent, grandparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law, sister-in-law, and shall include adoptive relationships.

     In addition, to the extent permitted by applicable law and the Rules promulgated under Section 16(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), the Plan Administrator may permit a recipient of a stock option to designate in writing during the Participant’s lifetime a beneficiary to receive and exercise stock options in the event of the Participant’s death (as provided in Section 5.5(b)). Except as otherwise provided for herein, any attempt to transfer, assign, pledge, hypothecate or otherwise dispose of any stock option under the Plan or of any right or privilege conferred thereby, contrary to the provisions of the Plan or such stock option, or the sale or levy or any attachment or similar process upon the rights and privileges conferred thereby, shall be null and void.

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Stock Option Plan For Non-Employee Directors Page 4

5.7   DEFERRAL ELECTION

     A Participant may elect irrevocably at any time prior to exercising a stock option granted under the Plan that issuance of Shares upon exercise of such option shall be deferred until the Participant reaches a pre-specified age or ceases to serve as a Director of the Company, as elected by the Participant. After the exercise of any such stock option and prior to the issuance of any deferred shares, the number of Shares issuable to the Participant shall be credited to a memorandum deferred account and any dividends or other distributions paid on the Common Stock shall be deemed reinvested in additional shares of Common Stock until all credited Shares shall become issuable pursuant to the Participant’s election.

SECTION 6 GENERAL PROVISIONS

     6.1 Neither the Plan, nor the granting of a stock option, nor any other action taken pursuant to the Plan shall constitute or be evidence of any agreement or understanding, express or implied, that a Participant has a right to continue as a Director for any period of time or at any particular rate of compensation.

     6.2 The Company shall not be required to issue any certificate or certificates for Shares upon the exercise of a stock option granted under the Plan, or record as a holder of record of Shares the name of the individual exercising an option under the Plan, (a) without obtaining to the complete satisfaction of the Plan Administrator the approval of all regulatory bodies deemed necessary by the Plan Administrator, and (b) without complying, to the Plan Administrator’s complete satisfaction, with all rules and regulations under federal, state or local law deemed applicable by the Plan Administrator.

     6.3 All costs and expenses of the adoption and administration of the Plan shall be borne by the Company.

     6.4 The Plan shall be construed and governed in accordance with the laws of the State of Texas, except that it shall be construed and governed in accordance with applicable federal law in the event that such federal law preempts state law.

     6.5 Appropriate provision shall be made for all taxes required to be withheld in connection with the exercise or other taxable event with respect to stock options under the applicable laws or regulations of any governmental authority, whether federal, state or local and whether domestic or foreign.

     By participating in the Plan, each Participant shall agree that he or she is responsible for obtaining qualified tax advice prior to the Participant’s (i) entering into any transaction under or with respect to the Plan, (ii) designating or choosing the times of distributions under the Plan, or (iii) disposing of any shares of Common Stock issued under the Plan.

El Paso Energy Corporation
Stock Option Plan For Non-Employee Directors Page 5

SECTION 7 EFFECTIVE DATE AND DURATION OF THE PLAN

     The original plan was dated as of January 1, 1992 and adopted by the Company’s Board and approved by the Company’s sole stockholder on January 15, 1992. The Board amended and restated the Plan effective as of August 1, 1998, in connection with the reorganization of the Company into a holding company structure whereby El Paso Energy Corporation became the publicly held company and El Paso Natural Gas Company became a wholly owned subsidiary. This Plan was assumed by El Paso Energy Corporation pursuant to an Assignment and Assumption Agreement effective as of August 1, 1998, by and between El Paso Energy Corporation and El Paso Natural Gas Company. The Board amended and restated the Plan effective as of January 20, 1999. The Plan shall continue in effect until it is terminated by action of the Board or the Company’s stockholders, but such termination shall not affect the then-outstanding terms of any stock options or the Company’s obligation to issue Shares under any then-exercised stock options as to which a deferral election has been made under Section 5.7.

SECTION 8 COMPLIANCE WITH SECTION 16

     The Company’s intention is that, so long as any of the Company’s equity securities are registered pursuant to Section 12(b) or 12(g) of the Exchange Act, with respect to awards granted to or held by Section 16 Insiders, the Plan shall comply in all respects with Rule 16b-3 or any successor rule or rule of similar application under Section 16 of the Exchange Act or rules thereunder, and, if any Plan provision is later found not to be in compliance with such exemption under Section 16 of the Exchange Act, that provision shall be deemed modified as necessary to meet the requirements of such applicable exemption.

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Stock Option Plan For Non-Employee Directors Page 6

SECTION 9 AMENDMENT, TERMINATION OR DISCONTINUANCE
OF THE PLAN

     9.1 Subject to the Board and Section 9.2, the Plan Administrator may from time to time make such amendments to the Plan as it may deem proper and in the best interest of the Company, including, but not limited to, any amendment necessary to ensure that the Company may obtain any regulatory approval referred to in Section 6.2; provided, however, that unless the Plan Administrator determines that such change does not materially impair the value of the stock options, no change in any stock option theretofore granted may be made which would impair the right of the Participant to acquire Shares or retain Shares that the Participant may have acquired as a result of the Plan without the consent of the Participant.

     9.2 The Board may at any time suspend the operation of or terminate the Plan with respect to any Shares which are not at that time subject to any outstanding stock options.

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Stock Option Plan For Non-Employee Directors Page 7

     IN WITNESS WHEREOF, the Company has caused the Plan to be amended and restated effective as of January 20, 1999.

EL PASO ENERGY CORPORATION
By:	/s/ Joel Richards III
Title:	Executive Vice President

ATTEST:

By	/s/ David L. Siddall
Title:	Corporate Secretary

El Paso Energy Corporation
Stock Option Plan For Non-Employee Directors Page 8

Created by 10K Wizard Technology   www.10KWizard.com

EX-10.G.1

EXHIBIT 10.G.1

AMENDMENT NO. 1 TO THE
STOCK OPTION PLAN
FOR NON-EMPLOYEE DIRECTORS

          Pursuant to Section 9.1 of the El Paso Energy Corporation Stock Option Plan for Non-Employee Directors, Amended and Restated Effective as of January 20, 1999 (the “Plan”), the Plan is hereby amended as follows, effective July 16, 1999:

          Section 3 is amended to read as follows:

“SECTION 3 ADMINISTRATION OF THE PLAN

     Unlessf otherwise determined by the Board and subject to Section 9, the Plan shall be administered by a management committee (the “Plan Administrator”) consisting of the Chief Executive Officer of the Company and such other senior officers as the Chief Executive Officer shall designate. The Plan Administrator shall interpret the Plan, shall prescribe, amend and rescind rules relating to the Plan from time to time as it deems proper and in the best interests of the Company, and shall take any other action necessary for the administration of the Plan.”

     IN WITNESS WHEREOF, the Company has caused this amendment to be duly executed on this 16th day of July, 1999.

EL PASO ENERGY CORPORATION
By:	/s/ Joel Richards III
	Joel Richards III
	Executive Vice President

Attest:

/s/ David L. Siddall

Corporate Secretary

EX-10.I

EXHIBIT 10.I

EL PASO ENERGY CORPORATION

1995 OMNIBUS COMPENSATION
PLAN

AMENDED AND RESTATED EFFECTIVE AS OF AUGUST 1, 1998

TABLE OF CONTENTS

SECTION 1 PURPOSES	1
SECTION 2 DEFINITIONS	1
2.1 Adjusted Value	1
2.2 Beneficiary	1
2.3 Board of Directors	1
2.4 Cause	1
2.5 Change in Control	2
2.6 Code	3
2.7 Common Stock	3
2.8 Exchange Act	3
2.9 Fair Market Value	3
2.10 Good Reason	4
2.11 Incentive Stock Option	5
2.12 Management Committee	5
2.13 Maximum Annual Employee Grant	5
2.14 Nonqualified Option	5
2.15 Option Price	5
2.16 Participant	5
2.17 Performance Cycle	5
2.18 Performance Goals	5
2.19 Performance Peer Group	6
2.20 Performance Period	6
2.21 Performance Ranking Position	6
2.22 Performance Unit or Units	6
2.23 Permanent Disability or Permanently Disabled	6
2.24 Plan Administrator	7
2.25 Restricted Stock	7
2.26 Rule 16b-3	7
2.27 Section 16 Insider	7
2.28 Section 162(m)	7
2.29 Subsidiary	7
2.30 Total Shareholder Return	7
2.31 Valuation Date	8
SECTION 3 ADMINISTRATION	8
SECTION 4 ELIGIBILITY	9
SECTION 5 SHARES AND UNITS AVAILABLE FOR THE PLAN	9

El Paso Energy Corporation
1995 Omnibus Compensation Plan i Table of Contents

SECTION 6 STOCK OPTIONS	10
SECTION 7 STOCK APPRECIATION RIGHTS	16
SECTION 8 LIMITED STOCK APPRECIATION RIGHTS	18
SECTION 9 PERFORMANCE UNITS	19
9.1 Grants of Units	19
9.2 Notice to Participants	19
9.3 Vesting	19
9.4 Valuation of Performance Units	20
9.5 Entitlement to Payment	21
9.6 Deferred Payment	23
9.7 Acceleration of Payment Due to Change in Control	23
9.8 Unfunded Obligation	24
9.9 Designation of Beneficiary	24
SECTION 10 RESTRICTED STOCK	24
SECTION 11 REGULATORY APPROVALS AND LISTING	26
SECTION 12 EFFECTIVE DATE AND TERM OF PLAN	27
SECTION 13 GENERAL PROVISIONS	28
SECTION 14 COMPLIANCE WITH RULE 16b-3 AND SECTION 162(m)	29
SECTION 15 AMENDMENT, TERMINATION OR DISCONTINUANCE OF THE PLAN	30

El Paso Energy Corporation
1995 Omnibus Compensation Plan ii Table of Contents

EL PASO ENERGY CORPORATION
1995 OMNIBUS COMPENSATION PLAN
AMENDED AND RESTATED EFFECTIVE AS OF AUGUST 1, 1998

SECTION 1 PURPOSES

     The purposes of the El Paso Energy Corporation 1995 Omnibus Compensation Plan (the “Plan”) are to promote the interests of El Paso Energy Corporation (the “Company”) and its stockholders by strengthening its ability to attract and retain officers and key management employees (“key management employees” means those employees who hold the position of department director) in the employ of the Company and its Subsidiaries (as defined below) by furnishing suitable recognition of their ability and industry which contributed materially to the success of the Company and to align the interests and efforts of the Company’s officers and key management employees to the long-term interests of the Company’s stockholders. The Plan provides for the grant of stock options, limited stock appreciation rights, stock appreciation rights, restricted stock and performance units in accordance with the terms and conditions set forth below.

SECTION 2 DEFINITIONS

     Unless otherwise required by the context, the following terms when used in the Plan shall have the meanings set forth in this Section 2:

2.1   ADJUSTED VALUE

     The dollar amount value of Performance Units determined as of a Valuation Date.

2.2   BENEFICIARY

     The person or persons designated by the Participant pursuant to Section 6.4(f) or Section 9.9 of this Plan to whom payments are to be paid pursuant to the terms of the Plan in the event of the Participant’s death.

2.3   BOARD OF DIRECTORS

     The Board of Directors of the Company.

2.4   CAUSE

     The Company may terminate the Participant’s employment for Cause. A termination for Cause is a termination evidenced by a resolution adopted in good faith by two-thirds (2/3) of the Board of Directors that the Participant (i) willfully and continually failed to substantially perform the Participant’s duties with the Company (other than a failure resulting from the Participant’s incapacity due to physical or mental illness) which

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1995 Omnibus Compensation Plan Page 1

failure continued for a period of at least thirty (30) days after a written notice of demand for substantial performance has been delivered to the Participant specifying the manner in which the Participant has failed to substantially perform or (ii) willfully engaged in conduct which is demonstrably and materially injurious to the Company, monetarily or otherwise; provided, however, that no termination of the Participant’s employment shall be for Cause as set forth in clause (ii) above until (A) there shall have been delivered to the Participant a copy of a written notice setting forth that the Participant was guilty of the conduct set forth in clause (ii) above and specifying the particulars thereof in detail and (B) the Participant shall have been provided an opportunity to be heard by the Board of Directors (with the assistance of the Participant’s counsel if the Participant so desires). No act, nor failure to act, on the Participant’s part shall be considered “willful” unless the Participant has acted, or failed to act, with an absence of good faith and without a reasonable belief that the Participant’s action or failure to act was in the best interest of the Company. Notwithstanding anything contained in the Plan to the contrary, no failure to perform by the Participant after notice of termination is given by the Participant shall constitute Cause.

2.5   CHANGE IN CONTROL

     As used in the Plan, a Change in Control shall be deemed to occur (i) if any person (as such term is used in Sections 13(d) and 14(d)(2) of the Exchange Act) is or becomes the “beneficial owner” (as defined in Rule 13d-3 of the Exchange Act), directly or indirectly, of securities of the Company representing twenty percent (20%) or more of the combined voting power of the Company’s then outstanding securities, (ii) upon the first purchase of the Common Stock pursuant to a tender or exchange offer (other than a tender or exchange offer made by the Company), (iii) upon the approval by the Company’s stockholders of a merger or consolidation, a sale or disposition of all or substantially all of the Company’s assets or a plan of liquidation or dissolution of the Company, or (iv) if, during any period of two (2) consecutive years, individuals who at the beginning of such period constitute the Board of Directors cease for any reason to constitute at least a majority thereof, unless the election or nomination for the election by the Company’s stockholders of each new director was approved by a vote of at least two-thirds (2/3) of the directors then still in office who were directors at the beginning of the period. Notwithstanding the foregoing, a Change in Control shall not be deemed to occur if the Company either merges or consolidates with or into another company or sells or disposes of all or substantially all of its assets to another company, if such merger, consolidation, sale or disposition is in connection with a corporate restructuring wherein the stockholders of the Company immediately before such merger, consolidation, sale or disposition own, directly or indirectly, immediately following such merger, consolidation, sale or disposition at least eighty percent (80%) of the combined voting power of all outstanding classes of securities of the company resulting from such merger or consolidation, or to which the Company sells or disposes of its assets, in substantially the same proportion as their ownership in the Company immediately before such merger, consolidation, sale or disposition.

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1995 Omnibus Compensation Plan Page 2

2.6   CODE

     The Internal Revenue Code of 1986, as amended and in effect from time to time, and the temporary or final regulations of the Secretary of the U.S. Treasury adopted pursuant to the Code.

2.7   COMMON STOCK

     The Common Stock of the Company, $3 par value per share, or such other class of shares or other securities as may be applicable pursuant to the provisions of Section 5.

2.8   EXCHANGE ACT

     The Securities Exchange Act of 1934, as amended.

2.9   FAIR MARKET VALUE

     As applied to a specific date, Fair Market Value shall be deemed to be the mean between the highest and lowest quoted selling prices at which Common Stock is sold on such date as reported in the NYSE-Composite Transactions by The Wall Street Journal on such date, or if no Common Stock was traded on such date, on the next preceding day on which Common Stock was so traded. Notwithstanding the foregoing, upon the exercise,

     (a) during the thirty (30) day period following a Change in Control, of a limited stock appreciation right or stock appreciation right granted in connection with a Nonqualified Option more than six (6) months prior to a Change in Control, or

     (b) during the seven (7) month period following a Change in Control, of a limited stock appreciation right or of a stock appreciation right granted in connection with a Nonqualified Option less than six (6) months prior to a Change in Control,

On or after a Change in Control, Fair Market Value on the date of exercise shall be deemed to be the greater of (i) the highest price per share of Common Stock as reported in the NYSE-Composite Transactions by The Wall Street Journal during the sixty (60) day period ending on the day preceding the date of exercise of the stock appreciation right or limited stock appreciation right, as the case may be, and (ii) if the Change in Control is one described in clause (ii) or (iii) of Section 2.5, the highest price per share paid for Common Stock in connection with such Change in Control.

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1995 Omnibus Compensation Plan Page 3

2.10   GOOD REASON

     Good Reason shall mean the occurrence of any of the following events or conditions:

     (a) a change in the Participant’s status, title, position or responsibilities (including reporting responsibilities) which, in the Participant’s reasonable judgment, represents a substantial reduction of the status, title, position or responsibilities as in effect immediately prior thereto; the assignment to the Participant of any duties or responsibilities which, in the Participant’s reasonable judgment, are inconsistent with such status, title, position or responsibilities; or any removal of the Participant from or failure to reappoint or reelect the Participant to any of such positions, except in connection with the termination of the Participant’s employment for Cause, for Permanent Disability or as a result of his or her death, or by the Participant other than for Good Reason;

     (b) a reduction in the Participant’s annual base salary;

     (c) the Company’s requiring the Participant (without the consent of the Participant) to be based at any place outside a thirty-five (35) mile radius of his or her place of employment prior to a Change in Control, except for reasonably required travel on the Company’s business which is not materially greater than such travel requirements prior to the Change in Control;

     (d) the failure by the Company to (i) continue in effect any material compensation or benefit plan in which the Participant was participating at the time of the Change in Control, including, but not limited to, the Plan, the El Paso Energy Corporation Pension Plan, the El Paso Energy Corporation Supplemental Benefits Plan, the El Paso Energy Corporation 1995 Incentive Compensation Plan, the El Paso Energy Corporation Deferred Compensation Plan and the El Paso Energy Corporation Retirement Savings Plan, with any amendments and restatements of such plans made prior to such Change in Control; or (ii) provide the Participant with compensation and benefits at least equal (in terms of benefit levels and/or reward opportunities) to those provided for under each employee benefit plan, program and practice as in effect immediately prior to the Change in Control (or as in effect following the Change in Control, if greater);

     (e) any material breach by the Company of any provision of the Plan; or

     (f) any purported termination of the Participant’s employment for Cause by the Company which does not otherwise comply with the terms of the Plan.

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1995 Omnibus Compensation Plan Page 4

2.11   INCENTIVE STOCK OPTION

     An option intended to meet the requirements of an Incentive Stock Option as defined in Section 422 of the Code, as in effect at the time of grant of such option, or any statutory provision that may hereafter replace such Section.

2.12   MANAGEMENT COMMITTEE

     A committee consisting of the Chief Executive Officer and such other senior officers as the Chief Executive Officer shall designate.

2.13   MAXIMUM ANNUAL EMPLOYEE GRANT

     The Maximum Annual Employee Grant set forth in Section 5.4.

2.14   NONQUALIFIED OPTION

     An option which is not intended to meet the requirements of an Incentive Stock Option as defined in Section 422 of the Code.

2.15   OPTION PRICE

     The price per share of Common Stock at which each option is exercisable.

2.16   PARTICIPANT

     An eligible employee to whom an option, limited stock appreciation right, stock appreciation right, Restricted Stock or Performance Unit is granted under the Plan as set forth in Section 4.

2.17   PERFORMANCE CYCLE

          That period commencing with January 1 of each year in which the grant of a Performance Unit is made and ending on December 31 of the third succeeding year, or such other time period as the Plan Administrator may determine. The Plan Administrator, it its discretion, may initiate an overlapping Performance Cycle that begins before an existing Performance Cycle has ended.

2.18   PERFORMANCE GOALS

     The Plan Administrator shall establish one or more performance goals (“Performance Goals”) for each Performance Period in writing. Such Performance Goals shall be set no later than the commencement of the applicable Performance Period, or such later date as may be permitted with respect to “performance-based” compensation under Section 162(m) of the Code.

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1995 Omnibus Compensation Plan Page 5

     Each Performance Goal selected for a particular Performance Period shall be a relative or absolute measure of any one or more of the following: Total Shareholder Return, operating income, pre-tax profit, earnings per share, cash flow, return on capital, return on equity, return on net assets, net income, debt reduction, safety, return on investment or revenues. The foregoing terms shall have the same meaning as used in the Company’s financial statements, or if the terms are not used in the Company’s financial statements, they shall have the meaning generally applied pursuant to general accepted accounting principles, or as used in the industry, as applicable.

2.19   PERFORMANCE PEER GROUP

     Those publicly held companies selected by the Plan Administrator prior to the commencement of a Performance Period, or such later date provided by the Code, to form a comparative performance group in applying Section 9.4.

2.20   PERFORMANCE PERIOD

     That period of time during which Performance Goals are measured to determine the vesting or granting of options, limited stock appreciation rights, stock appreciation rights, Restricted Stock or Performance Units, as the Plan Administrator may determine.

2.21   PERFORMANCE RANKING POSITION

     The relative placement of the Company’s Total Shareholder Return measured against the Total Shareholder Return of the other companies in the Performance Peer Group for which purposes rank shall be determined by quartile, with a ranking in the first (1st) quartile (e.g., the Company’s Total Shareholder Return is equal to or greater than the Total Shareholder Return of at least seventy-five percent (75%) of the Performance Peer Group) corresponding to the highest quartile of Total Shareholder Return.

2.22   PERFORMANCE UNIT OR UNITS

     Units of long-term incentive compensation granted to a Participant with respect to a particular Performance Cycle.

2.23   PERMANENT DISABILITY OR PERMANENTLY DISABLED

     A Participant shall be deemed to have become Permanently Disabled for purposes of the Plan if the Chief Executive Officer of the Company shall find upon the basis of medical evidence satisfactory to the Chief Executive Officer that the Participant is totally disabled, whether due to physical or mental condition, so as to be prevented from engaging in further employment by the Company or any of its Subsidiaries, and that such disability will be permanent and continuous during the remainder of the Participant’s life; provided, that with respect to Section 16 Insiders such determination shall be made by the Plan Administrator.

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1995 Omnibus Compensation Plan Page 6

2.24   PLAN ADMINISTRATOR

     The Board of Directors or the committee appointed and/or authorized pursuant to Section 3 to administer the Plan.

2.25   RESTRICTED STOCK

     Common Stock granted under the Plan that is subject to the requirements of Section 10 and such other restrictions as the Plan Administrator deems appropriate. References to Restricted Stock in this Plan shall include Performance Restricted Stock (as defined in Section 5.2) unless the context otherwise requires.

2.26   RULE 16b-3

     Rule 16b-3 of the General Rules and Regulations under the Exchange Act.

2.27   SECTION 16 INSIDER

     Any person who is selected by the Plan Administrator to receive options, limited stock appreciation rights, stock appreciation rights, Restricted Stock and/or Performance Units pursuant to the Plan and who is subject to the requirements of Section 16 of the Exchange Act, and the rules and regulations promulgated thereunder.

2.28   SECTION 162(m)

     Section 162(m) of the Code, and regulations promulgated thereunder.

2.29   SUBSIDIARY

     An entity that is designated by the Plan Administrator as a subsidiary for purposes of the Plan and that is a corporation (or other form of business association that is treated as a corporation for tax purposes) of which shares (or other ownership interests) having more than fifty percent (50%) of the voting power are owned or controlled, directly or indirectly, by the Company so as to qualify as a “subsidiary corporation” (within the meaning of Section 424(f) of the Code).

2.30   TOTAL SHAREHOLDER RETURN

     The sum of (i) the appreciation or depreciation in the price of a share of a company’s common stock, and (ii) the dividends and other distributions paid during the applicable Performance Cycle, expressed as a percentage basis of the Fair Market Value of such share on the first day of the applicable Performance Cycle, as calculated in a manner determined by the Plan Administrator.

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1995 Omnibus Compensation Plan Page 7

2.31   VALUATION DATE

     The date for determining the Adjusted Value of vested Units that will be paid or credited to the Participant or Beneficiary in accordance with Section 9.5 or 9.6. The Valuation Date shall occur on the last day of the applicable Performance Cycle, or such other time as provided in this Plan, or as the Plan Administrator may select. The Valuation Date for each Performance Cycle shall be set forth in the grant of Performance Units and shall be established no later than the date on which the Performance Goals for a particular Performance Cycle are selected, except as otherwise specifically provided herein.

SECTION 3 ADMINISTRATION

     3.1 The Plan shall be administered by the Board of Directors or, in the event the Board of Directors shall appoint and/or authorize a committee to administer the Plan, by such committee.

     No member of the Board of Directors or the committee shall vote with respect directly to the granting of options, limited stock appreciation rights, stock appreciation rights, Restricted Stock and/or Performance Units hereunder to himself or herself, as the case may be, and, if state corporate law does not permit a committee to grant options, limited stock appreciation rights, stock appreciation rights, Restricted Stock and Performance Units to directors, then any option, limited stock appreciation right, stock appreciation right, Restricted Stock or Performance Unit granted under the Plan to a director for his or her services as such shall be approved by the full Board of Directors.

     The members of any committee serving as Plan Administrator shall be appointed by the Board of Directors for such term as the Board of Directors may determine. The Board of Directors may from time to time remove members from, or add members to, the committee. Vacancies on the committee, however caused, may be filled by the Board of Directors.

     With respect to grants made under the Plan to Section 16 Insiders, the Plan Administrator shall be constituted at all times so as to meet the disinterested administration requirements of Rule 16b-3 and the outside director requirements of Section 162(m) so long as any of the Company’s equity Securities are registered pursuant to Section 12(b) or 12(g) of the Exchange Act.

     3.2 Except for the terms and conditions explicitly set forth in the Plan, the Plan Administrator shall have sole authority to construe and interpret the Plan, to establish, amend and rescind rules and regulations relating to the Plan, to select persons eligible to participate in the Plan, to grant options, limited stock appreciation rights, stock appreciation rights, Restricted Stock and Performance Units thereunder, to administer the Plan, to make recommendations to the Board of Directors, and to take all such steps and

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1995 Omnibus Compensation Plan Page 8

make all such determinations in connection with the Plan and the options, limited stock appreciation rights, stock appreciation rights, Restricted Stock and Performance Units granted thereunder as it may deem necessary or advisable, which determination shall be final and binding upon all Participants, so long as such interpretation and construction with respect to Incentive Stock Options corresponds to any applicable requirements of Section 422 of the Code. The Plan Administrator shall cause the Company at its expense to take any action related to the Plan which may be necessary to comply with the provisions of any federal or state law or any regulations issued thereunder.

     3.3 Each member of any committee acting as Plan Administrator, while serving as such, shall be considered to be acting in his or her capacity as a director of the Company. Members of the Board of Directors and members of any committee acting under the Plan shall be fully protected in relying in good faith upon the advice of counsel and shall incur no liability except for gross negligence or willful misconduct in the performance of their duties.

SECTION 4 ELIGIBILITY

     To be eligible for selection by the Plan Administrator to participate in the Plan, an individual must be an officer or key management employee of the Company, or of any Subsidiary, as of the date on which the Plan Administrator grants to such individual an option, limited Stock appreciation right, stock appreciation right, Restricted Stock or Performance Unit or a person who, in the judgment of the Plan Administrator, holds a position of responsibility and is able to contribute substantially to the Company’s continued success. Members of the Board of Directors of the Company who are full-time salaried officers shall be eligible to participate. Members of the Board of Directors who are not employees are not eligible to participate in this Plan.

SECTION 5 SHARES AND UNITS AVAILABLE FOR THE PLAN

     5.1 Subject to Section 5.5, the maximum number of shares that may be issued upon settlement of Performance Units and for which options, limited stock appreciation rights, stock appreciation rights and Restricted Stock may at any time be granted under the Plan is six million (6,000,000) shares of Common Stock, from shares held in the Company’s treasury or out of authorized but unissued shares of the Company, or partly out of each, as shall be determined by the Board of Directors, subject to, and reduced by (on a post-split basis), the number of shares of Common Stock awarded prior to the occurrence of a two-for-one stock split effected by the Company in the form of a 100% stock dividend on April 1, 1998. Any options, limited stock appreciation rights, stock appreciation rights and shares of Restricted Stock outstanding under the Plan on April 1, 1998, shall be adjusted on a two-for-one basis to reflect the stock dividend.

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1995 Omnibus Compensation Plan Page 9

     5.2 Notwithstanding the foregoing, and subject to Section 5.5, the number of shares for which Restricted Stock may be granted pursuant to Section 10 of the Plan may not exceed one million (1,000,000) shares of Common Stock, unless the granting or vesting of such Restricted Stock is in compliance with the performance-based requirements of Section 162(m) (the “Performance Restricted Stock”), subject to, and reduced by (on a post-split basis), the number of shares of Common Stock awarded prior to the occurrence of a two-for-one stock split effected by the Company in the form of a 100% stock dividend on April 1, 1998. Any shares of Restricted Stock outstanding under the Plan on April 1, 1998, shall be adjusted on a two-for-one basis to reflect the stock dividend. The grant of Performance Restricted Stock is not limited by this Section 5.2.

     5.3 Subject to Section 5.5, the number of Performance Units which may be granted under the Plan is set at three hundred thousand (300,000) Units. Units that have been granted and are fully vested or that still may become fully vested under the terms of the Plan shall reduce the number of outstanding Units that are available for use in making future grants under the Plan.

     5.4 The maximum number of shares, as calculated in accordance with the provisions of Section 5.1, with respect to which awards under this Plan may be granted to any eligible employee in any one year shall not exceed: (a) one million (1,000,000) in the case of options (and related limited stock appreciation rights or stock appreciation rights) or issued upon settlement of Performance Units; and (b) one million (1,000,000) in the case of shares of Restricted Stock (whether or not such Restricted Stock is Performance Restricted Stock). With respect to Performance Units, the maximum Units granted to any eligible employee shall not exceed seventy-five thousand (75,000) Performance Units in any Performance Cycle. Each of the foregoing maximums shall be referred to collectively as the “Maximum Annual Employee Grant.”

     5.5 In the event of a recapitalization, stock split, stock dividend, exchange of shares, merger, reorganization, change in corporate structure or shares of the Company or similar event, the Board of Directors, upon the recommendation of the Plan Administrator, may make appropriate adjustments in the number of shares authorized for the Plan, the Maximum Annual Employee Grant and, with respect to outstanding options, limited stock appreciation rights, stock appreciation rights, and Restricted Stock, the Plan Administrator may make appropriate adjustments in the number of shares and the Option Price.

SECTION 6 STOCK OPTIONS

     6.1 Options may be granted to eligible employees in such number, and at such times during the term of the Plan as the Plan Administrator shall determine, the Plan Administrator taking into account the duties of the respective employees, their present and potential contributions to the success of the Company, and such other factors as the Plan Administrator shall deem relevant in accomplishing the purposes of the Plan. The

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granting of an option shall take place when the Plan Administrator by resolution, written consent or other appropriate action determines to grant such an option to a particular Participant at a particular price. Each option shall be evidenced by a written instrument delivered by or on behalf of the Company containing provisions not inconsistent with the Plan.

     6.2 An option granted under the Plan may be either an Incentive Stock Option or a Nonqualified Option.

     6.3 Each provision of the Plan and each Incentive Stock Option granted thereunder shall be construed so that each such option shall qualify as an Incentive Stock Option, and any provision thereof that cannot be so construed shall be disregarded, unless the Participant agrees otherwise. The total number of shares which may be purchased upon the exercise of Incentive Stock Options granted under the Plan shall not exceed the total specified in Section 5.1. Incentive Stock Options, in addition to complying with the other provisions of the Plan relating to options generally, shall be subject to the following conditions:

(a)   Ten Percent (10%) Stockholders

     A Participant must not, immediately before an Incentive Stock Option is granted, own stock representing more than ten percent (10%) of the voting power or value of all classes of stock of the Company or of a Subsidiary. This requirement is waived if (i) the Option Price of the Incentive Stock Option to be granted is at least one hundred ten percent (110%) of the Fair Market Value of the stock subject to the option, determined at the time the option is granted, and (ii) the option is not exercisable more than five (5) years from the date the option is granted.

(b)   Annual Limitation

     To the extent that the aggregate Fair Market Value (determined at the time of the grant of the option) of the stock with respect to which Incentive Stock Options are exercisable for the first time by the Participant during any calendar year exceeds One Hundred Thousand Dollars ($100,000), such options shall be treated as Nonqualified Options.

(c)   Additional Terms

     Any other terms and conditions which the Plan Administrator determines, upon advice of counsel, must be imposed for the option to
be an Incentive Stock Option.

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1995 Omnibus Compensation Plan Page 11

     6.4 Except as otherwise provided in Section 6.3, all Incentive Stock Options and Nonqualified Options under the Plan shall be granted subject to the following terms and conditions:

(a)   Option Price

     The Option Price shall be determined by the Plan Administrator, but shall not be less than one hundred percent (100%) of the Fair Market Value of the Common Stock on the date the option is granted.

(b)   Duration of Options

     Options shall be exercisable at such time and under such conditions as set forth in the option grant, but in no event shall any Incentive Stock Option be exercisable subsequent to the day before the tenth anniversary of the date on which the option is granted, nor shall any other option be exercisable later than the tenth anniversary of the date of its grant.

(c)   Exercise of Options

     Subject to Section 6.4(j), a Participant may not exercise an option until the Participant has completed one (1) year of continuous employment with the Company or any of its Subsidiaries from and including the date on which the option is granted, or such longer period as the Plan Administrator may determine in a particular case. This requirement is waived in the event of death or Permanent Disability of a Participant before such period of continuous employment is completed and may be waived or modified in the agreement evidencing the option or by resolution adopted at any time by the Plan Administrator. Thereafter, shares of Common Stock covered by an option may be purchased at one time or in such installments over the balance of the option period as may be provided in the option grant. Any shares not purchased on the applicable installment date may be purchased thereafter at any time prior to the final expiration of the option. To the extent that the right to purchase shares has accrued thereunder, options may be exercised from time to time by written notice to the Company setting forth the number of shares with respect to which the option is being exercised.

(d)   Payment

     The purchase price of shares purchased under options shall be paid in full to the Company upon the exercise of the option by delivery of consideration equal to the product of the Option Price and the number of shares purchased (the “Purchase Price”). Such consideration may be either (i) in cash or (ii) at the discretion of the Plan Administrator, in Common Stock already owned by the Participant for at least six (6) months, or any combination of cash and Common

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Stock. The Fair Market Value of such Common Stock as delivered shall be valued as of the day prior to delivery. The Plan Administrator can determine at the time the option is granted that additional forms of payment will be permitted. To the extent permitted by the Plan Administrator and applicable laws and regulations (including, but not limited to, federal tax and securities laws, regulations and state corporate law), an option may also be exercised by delivery of a properly executed exercise notice together with irrevocable instructions to a broker to promptly deliver to the Company the amount of sale or loan proceeds to pay the Purchase Price. A Participant shall have none of the rights of a stockholder until the shares of Common Stock are issued to the Participant.

     If specifically authorized in the option grant, a Participant may elect to pay all or a portion of the Purchase Price by having shares of Common Stock with a Fair Market Value equal to all or a portion of the Purchase Price be withheld from the shares issuable to the Participant upon the exercise of the option. The Fair Market Value of such Common Stock as is withheld shall be determined as of the same day as the exercise of the option. In the event an option grant to a Section 16 Insider provides that the Purchase Price may be paid in whole or in part by having shares with a Fair Market Value equal to all or a portion of the Purchase Price withheld from the shares issuable to the Participant upon the exercise of the option, the following restrictions shall apply. To the extent required for compliance with Rule 16b-3, the withholding of shares issuable upon the exercise of an option to pay the Purchase Price by a Section 16 Insider must be approved by the Plan Administrator and must be made (x) pursuant to an irrevocable election made six (6) months in advance of the transaction, (y) during the period beginning on the third business day following the date of release for publication of the quarterly or annual summary statements of sales and earnings of the Company and ending on the twelfth business day following such date, or (z) otherwise in accordance with Rule 16b-3 and interpretations thereunder.

(e)   Restrictions

     The Plan Administrator shall determine and reflect in the option grant, with respect to each option, the nature and extent of the restrictions, if any, to be imposed on the shares of Common Stock which may be purchased thereunder, including, but not limited to, restrictions on the transferability of such shares acquired through the exercise of such options for such periods as the Plan Administrator may determine and, further, that in the event a Participant’s employment by the Company, or a Subsidiary, terminates during the period in which such shares are nontransferable, the Participant shall be required to sell such shares back to the Company at such prices as the Plan Administrator may specify in the option.

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(f)   Nontransferability of Options

     During a Participant’s lifetime, an option may be exercisable only by the Participant. Options granted under the Plan and the rights and privileges conferred thereby shall not be subject to execution, attachment or similar process and may not be transferred, assigned, pledged or hypothecated in any manner (whether by operation of law or otherwise) other than by will or by the applicable laws of descent and distribution. Notwithstanding the foregoing, to the extent permitted by applicable law and Rule 16b-3, the Plan Administrator may permit a recipient of a Nonqualified Option to designate in writing during the Participant’s lifetime a Beneficiary to receive and exercise the Participant’s Nonqualified Options in the event of such Participant’s death (as provided in Section 6.4(i)). A designation by a Participant under the Company’s Omnibus Compensation Plan dated as of January 1, 1992 (the “Predecessor Plan”) shall remain in effect under the Plan for any options unless such designation is revoked or changed under the Plan. If any Participant attempts to transfer, assign, pledge, hypothecate or otherwise dispose of any option under the Plan or of any right or privilege conferred thereby, contrary to the provisions of the Plan, or suffers the sale or levy or any attachment or similar process upon the rights and privileges conferred hereby, all affected options held by such Participant shall be immediately forfeited.

(g)   Purchase for Investment

     The Plan Administrator shall have the right to require that each Participant or other person who shall exercise an option under the Plan, and each person into whose name shares of Common Stock shall be issued pursuant to the exercise of an option, represent and agree that any and all shares of Common Stock purchased pursuant to such option are being purchased for investment only and not with a view to the distribution or resale thereof and that such shares will not be sold except in accordance with such restrictions or limitations as may be set forth in the option. This Section 6.4(g) shall be inoperative during any period of time when the Company has obtained all necessary or advisable approvals from governmental agencies and has completed all necessary or advisable registrations or other qualifications of shares of Common Stock as to which options may from time to time be granted as contemplated in Section 11.

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(h)   Termination of Employment

     Upon the termination of a Participant’s employment for any reason other than death or Permanent Disability, the Participant’s option shall be exercisable only to the extent that it was then exercisable and, unless the term of the options expires sooner, such options shall expire according to the following schedule; provided, that the Plan Administrator may at any time determine in a particular case that specific limitations and restrictions under the Plan shall not apply:

(i)   Retirement

     The option shall expire, unless exercised, thirty-six (36) months after the Participant’s retirement from the Company or any Subsidiary.

(ii)   Disability

     The option shall expire, unless exercised, thirty-six (36) months after the Participant’s Permanent Disability.

(iii)   Termination

     Subject to subparagraph (iv) below, the option shall expire, unless exercised, thirty-six (36) months after a Participant resigns or is terminated as an employee of the Company or any of its Subsidiaries, unless the Chief Executive Officer of the Company shall have determined in a specific case that the option should expire sooner or should terminate when the Participant’s employment status ceases; provided, however, that for Section 16 Insiders, such determination shall be made by the Plan Administrator.

(iv)   Termination Following a Change in Control

     The option shall expire, unless exercised, thirty-six (36) months after a Participant’s termination of employment (other than a termination by the Company for Cause or a voluntary termination by the Participant other than for Good Reason) following a Change in Control, provided that said termination of employment occurs within two (2) years following a Change in Control.

(v)   All Other Terminations

     Notwithstanding subparagraphs (iii) and (iv) above, the option shall expire upon termination of employment for Cause and any option intended to qualify as an Incentive Stock Option shall expire, unless exercised, one year after the Participant’s termination of employment on

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account of disability (as defined in Section 22(e)(3) of the Code) and shall expire three (3) months after the Participant’s termination of employment other than on account of death, Permanent Disability or termination for Cause, or following a Change in Control.

(i)   Death of Participant

     Upon the death of a Participant, whether during the Participant’s period of employment or during the thirty-six (36) month period referred to in Sections 6.4(h)(i), (ii) and (iii), the option shall expire, unless the original term of the option expires sooner, twelve (12) months after the date of the Participant’s death, unless the option is exercised within such twelve (12) month period by the Participant’s Beneficiary, legal representatives, estate or the person or persons to whom the deceased’s option rights shall have passed by will or the laws of descent and distribution; provided, that the Plan Administrator shall determine in a particular case that specific limitations and restrictions under the Plan shall not apply. Notwithstanding any other Plan provisions pertaining to the times at which options may be exercised, no option shall continue to be exercisable, pursuant to Section 6.4(h) or this Section 6.4(i), at a time that would violate the maximum duration of Section 6.4(b).

(j)   Change in Control

     Notwithstanding other Plan provisions pertaining to the times at which options may be exercised, all outstanding options, to the extent not then currently exercisable, shall become exercisable in full upon the occurrence of a Change in Control. In no event, however, shall any intended Incentive Stock Option, without notice to and consent of the Participant, first become exercisable, pursuant to Section 6.4(c) or this Section 6.4(j), if the result would be to cause such option, when granted, not to be treated as an Incentive Stock Option (whether by reason of the possible future violation of the annual limitation of Section 6.3(b) or otherwise). In addition, no option (whether or not intended to be an Incentive Stock Option) shall continue to be exercisable, pursuant to Sections 6.4(h) and 6.4(i), at a time that would violate the maximum duration of Section 6.4(b).

SECTION 7 STOCK APPRECIATION RIGHTS

     7.1 The Plan Administrator may grant stock appreciation rights to Participants in connection with any option granted under the Plan, either at the time of the grant of such option or at any time thereafter during the term of the option. Such stock appreciation rights shall cover the same shares covered by the options (or such lesser number of shares of Common Stock as the Plan Administrator may determine) and shall, except as provided in Section 7.3, be subject to the same terms and conditions as the

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related options and such further terms and conditions not inconsistent with the Plan as shall from time to time be determined by the Plan Administrator.

     7.2 Each stock appreciation right shall entitle the holder of the related option to surrender to the Company unexercised the related option, or any portion thereof, and to receive from the Company in exchange therefor an amount equal to the excess of the Fair Market Value of one share of Common Stock on the date the right is exercised over the Option Price per share times the number of shares covered by the option, or portion thereof, which is surrendered. Payment shall be made in shares of Common Stock valued at Fair Market Value as of the date the right is exercised, or in cash, or partly in shares and partly in cash, at the discretion of the Plan Administrator; provided, however, that payment shall be made solely in cash with respect to a stock appreciation right which is exercised within seven (7) months following a Change in Control. Notwithstanding the foregoing and to the extent required by Rule 16b-3, a payment, in whole or in part, of cash upon exercise of a stock appreciation right by a Section 16 Insider may be made only if the Plan Administrator approves such election to receive cash and the right is exercised during the period beginning on the third business day following the date of release for publication of the quarterly or annual summary statements of sales and earnings of the Company and ending on the twelfth business day following such date. Stock appreciation rights may be exercised from time to time upon actual receipt by the Company of written notice stating the number of shares of Common Stock with respect to which the stock appreciation right is being exercised. The value of any fractional shares shall be paid in cash.

     7.3 Stock appreciation rights are subject to the following restrictions:

     (a) Each stock appreciation right shall be exercisable at such time or times as the option to which it relates shall be exercisable, or at such other times as the Plan Administrator may determine; provided, however, that such right shall not be exercisable until the Participant shall have completed a six (6) month period of continuous employment with the Company or any of its Subsidiaries immediately following the date on which the stock appreciation right is granted. In the event of death or Permanent Disability of a Participant during employment but before the Participant has completed such period of continuous employment, such stock appreciation right shall be exercisable; but only within the period specified in the related option. In the event of a Change in Control, the requirement that a Participant shall have completed a six (6) month period of continuous employment is waived with respect to a Participant who is employed by the Company at the time of the Change in Control but who, within the six (6) month period, voluntarily terminates employment for Good Reason or is terminated by the Company other than for Cause. Notwithstanding the foregoing, a stock appreciation right may not be exercised for cash by a Section 16 Insider under any circumstances until the expiration of the six (6) month period required under Rule 16b-3.

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     (b) Except in the event of a Change in Control, the Plan Administrator in its sole discretion may approve or deny in whole or in part a request to exercise a stock appreciation right. Denial or approval of such request shall not require a subsequent request to be similarly treated by the Plan Administrator.

     (c) The right of a Participant to exercise a stock appreciation right shall be canceled if and to the extent the related option is exercised. To the extent that a stock appreciation right is exercised, the related option shall be deemed to have been surrendered unexercised and canceled.

     (d) A holder of stock appreciation rights shall have none of the rights of a stockholder until shares of Common Stock, if any, are issued to such holder pursuant to such holder’s exercise of such rights.

     (e) The acquisition of Common Stock pursuant to the exercise of a stock appreciation right shall be subject to the same restrictions as would apply to the acquisition of Common Stock acquired upon acquisition of the related option, as set forth in Section 6.4.

SECTION 8 LIMITED STOCK APPRECIATION RIGHTS

     8.1 The Plan Administrator may grant limited stock appreciation rights to Participants in connection with any options granted under the Plan, either at the time of the grant of such option or at any time thereafter during the term of the option. Such limited stock appreciation rights shall cover the same shares covered by the options (or such lesser number of shares of Common Stock as the Plan Administrator may determine) and shall, except as provided in Section 8.3, be subject to the same terms and conditions as the related options and such further terms and conditions not inconsistent with the Plan as shall from time to time be determined by the Plan Administrator.

     8.2 Each limited stock appreciation right shall entitle the holder of the related option to surrender to the Company the unexercised portion of the related option and to receive from the Company in exchange therefor an amount in cash equal to the excess of the Fair Market Value of one (1) share of Common Stock on the date the right is exercised over the Option Price per share times the number of shares covered by the option, or portion thereof, which is surrendered.

     8.3 Limited stock appreciation rights are subject to the following restrictions:

     (a) Each limited stock appreciation right shall be exercisable in full for a period of seven (7) months following the date of a Change in Control regardless of whether the holder is employed by the Company or any of its Subsidiaries on the date the right is exercised; provided, however, that limited stock appreciation rights may not be exercised under any circumstances until the expiration of the six (6) month period required under Rule 16b-3. Limited stock appreciation rights

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shall be exercisable only to the same extent and subject to the same conditions as the options related thereto are exercisable, as provided in Section 6.4(j).

     (b) The right of a Participant to exercise a limited stock appreciation right shall be canceled if and to the extent the related option is exercised. To the extent that a limited stock appreciation right is exercised, the related option shall be deemed to have been surrendered unexercised and canceled.

SECTION 9 PERFORMANCE UNITS

9.1   GRANTS OF UNITS

     Subject to the Maximum Annual Employee Grant, Units may be granted to Participants in such number as the Plan Administrator shall determine, taking into account the duties of the respective Participants, their present and potential contributions to the success of the Company or its Subsidiaries, their compensation provided by other incentive plans, their salaries, and such other factors as the Plan Administrator shall deem appropriate. Normally, Units will be granted only at the beginning of each Performance Cycle except in cases where a prorated grant may be made in mid-cycle to a newly eligible Participant or a Participant whose job responsibilities have significantly changed during the cycle.

9.2   NOTICE TO PARTICIPANTS

     The Plan Administrator shall notify each Participant in writing of the grant of Units to the Participant. Such notice shall set forth the Total Shareholder Return requirements, vesting schedule and such other terms and conditions applicable to such Units.

9.3   VESTING

(a)   Vesting Schedule

     The Plan Administrator shall adopt a vesting schedule for each year of a Performance Cycle. Vesting of Units for each year may (i) occur automatically after a Participant has completed the specified period of continuous employment with the Company or any of its Subsidiaries from the date of grant of such Units, (ii) be contingent upon attaining certain levels of Total Shareholder Return for the year in which the Units are eligible to vest, or (iii) occur at such other times or subject to such other criteria as the Plan Administrator may determine. The Plan Administrator may, in its discretion, alter the vesting guidelines in the event of unusual circumstances provided that to the extent applicable any such discretion shall be exercised in a manner consistent with Section 162(m). Vesting of Units with respect to Participants who begin participation or receive an additional grant

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of Units during the Performance Cycle will be determined by the Plan Administrator at the time of grant.

(b)   Change in Control

     Notwithstanding the foregoing vesting provisions, all unvested Units shall become fully vested on a pro rata basis measured in the nearest whole year between (i) the date of grant and (ii) the date of a Change in Control. In the event of termination of the Participant’s employment within two (2) years following a Change in Control but subsequent to the Change in Control, for any reason other than (i) the Participant’s death, (ii) the Participant’s Permanent Disability, (iii) Cause, or (iv) by the Participant without Good Reason, all unvested Units shall become fully vested on a pro rata basis measured in the nearest whole year between (i) the date of a Change in Control and (ii) the Participant’s termination.

9.4   VALUATION OF PERFORMANCE UNITS

     All Performance Units granted to Participants under the Plan shall be valued as follows:

(a)   Initial and Continuing Value

     Each Performance Unit shall have an initial value of one hundred dollars ($100) as of the date of the grant of Performance Units. Except where the Adjusted Value of Performance Units is determined as provided under Section 9.4(b), each Performance Unit shall continue to have a dollar value of one hundred dollars ($100) on each date subsequent to the date of grant of the Performance Unit.

(b)   Adjusted Value

     The determination of the Adjusted Value of Performance Units for benefit payments under Sections 9.5(b)(i) and 9.5(b)(ii) as of any relevant Valuation Date shall be made based on the Company’s Performance Ranking Position for the applicable Performance Cycle compared to the Performance Ranking Position of the Performance Peer Group, based on the following schedule:

Company’s Performance	Adjusted
Ranking Position	Value
1st Quartile	$	150
2nd Quartile		100
3rd Quartile		50
4th Quartile		0

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9.5   ENTITLEMENT TO PAYMENT

(a)   Performance Certification

     The Plan Administrator shall certify in writing, prior to payment of the Performance Units pursuant to this Section 9.5, the Company’s Performance Ranking Position. In no event will an award be payable under this Section 9 if the Company’s Performance Ranking Position is in the fourth (4th) quartile.

(b)   Eligibility for Benefit Payments

     Benefit payments with respect to vested Performance Units shall be paid under the following circumstances:

(i)   Primary Benefit Payment

     Upon the expiration of each Performance Cycle, all uncanceled Performance Units granted with respect to such Performance Cycle shall vest and benefit payments with respect to such Performance Units shall become payable. A Participant who has remained an employee continuously from the date of the grant of the Performance Units for a Performance Cycle through the last day of such Performance Cycle shall be eligible to receive a benefit payment equal to the Adjusted Value, as provided for in Section 9.4(b), of the Performance Units (the “Primary Benefit”) with respect to and as of the close of such Performance Cycle. The Valuation Date for determining such Adjusted Value shall be established by the Plan Administrator at the time the Performance Units are granted. The amount of any benefit payment payable with respect to Performance Units shall be reduced by the amount of any interim benefit payments made pursuant to Section 9.5(b)(ii) with respect to such Performance Units. If the interim benefit payments exceed the Primary Benefit, no payment shall be made.

(ii)   Interim Benefit Payments

     The Plan Administrator may in its sole discretion provide for an interim benefit payment to be made to a Participant with respect to Performance Units granted for any particular Performance Cycle. The right to any interim benefit payment shall be set forth in the grant of Performance Units to a Participant and must establish the terms and conditions of such interim benefit payment (including the Company’s Total Shareholder Return which must be attained during such Performance Period). An interim benefit payment may be provided for after the second year of a Performance Cycle. The interim benefit payment shall be based upon the Adjusted Value of the Performance Units, as provided for in

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Section 9.4(b) for the period up to the date of the interim payment valuation, and the amount of any such payment shall not exceed fifty percent (50%) of such Adjusted Value for the Performance Units which are vested at the end of the second year; provided, however, that such interim payment will be made only if the Company’s Performance Ranking Position is in the first (1st) or second (2nd) quartile. The Valuation Date for determining such Adjusted Value shall be set forth in the grant of Performance Units. The Performance Units which are valued for the interim benefit payment shall also be valued in accordance with Section 9.5(b)(i) or Section 9.7 if applicable, to determine what, if any, additional value the Participant may be entitled to. Interim benefit payments shall be made to those Participants who have remained employees continuously from the date of the grant of the applicable Performance Units until the date of the interim benefit payment relating to such Performance Units. The amount of any benefit payment payable with respect to Performance Units pursuant to Sections 9.5(b)(i) and 9.5(d) shall be reduced by the amount of any interim benefit payment made pursuant to this Section 9.5(b)(ii), but not below zero.

(c)   Form of Payment

     A Participant or a Participant’s Beneficiary shall be entitled to receive from the Company a benefit payment as provided pursuant to Sections 9.5(b)(i) or 9.5(b)(ii), as applicable, equal to the product of the Adjusted Value and the number of vested Units of a Participant. Such payment shall be made as soon as practicable following the applicable Valuation Date in accordance with this Section 9.5(c).

     Except as provided in Sections 9.5(d) and 9.7, benefit payments made to a Participant pursuant to this Section 9, shall be made as follows:

(i) Participants employed by the Company holding the position of Chairman of the Board, President or Chief Executive Officer and Participants employed by Company Subsidiaries holding equivalent positions, but not necessarily the same title, shall receive their Performance Unit payout as follows:

(A) 50% (fifty percent) in cash and

(B) 50% (fifty percent) in Common Stock.

(ii) Participants employed by the Company holding the position of Vice Chairman of the Board, Chief Operating Officer, or Executive Vice President and Participants employed by Company Subsidiaries holding equivalent positions, but not necessarily the same title, shall receive their Performance Unit payout as follows:

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(A) 60% (sixty percent) in cash and

(B) 40% (forty percent) in Common Stock.

(iii) Participants employed by the Company holding the position of Senior Vice President and Participants employed by Company Subsidiaries holding equivalent positions, but not necessarily the same title, shall receive their Performance Unit payout as follows:

(A) 75% (seventy-five percent) in cash and

(B) 25% (twenty-five percent) in Common Stock.

(d)   Retirement, Death, Disability or Termination of Employment

     Participants (or their Beneficiaries in the case of their deaths) who have retired, died, become Permanently Disabled, or who have terminated their employment, prior to the end of a Performance Cycle shall not be entitled to receive payment from the Company or its Subsidiaries for any Units which were not vested as of the time such Participants ceased active employment with the Company or its Subsidiaries. Notwithstanding Section 9.5(c), such Participants (or their Beneficiaries in the case of their deaths) will be entitled to receive a cash payment for vested Units in accordance with Section 9.5(b)(i). No payments shall be made to such Participants (or Beneficiaries) pursuant to Section 9.5(b)(ii).

9.6   DEFERRED PAYMENT

     Prior to the time that Units first vest pursuant to Section 9.3, the Participant may, subject to the consent of the Management Committee and in accordance with procedures that the Management Committee has approved, elect to have all or a portion (subject to a $1,000 minimum) of the lump-sum cash payment payable pursuant to Section 9.5(c) with respect to such vested Units deferred according to the terms and conditions of the Company’s Deferred Compensation Plan.

9.7   ACCELERATION OF PAYMENT DUE TO CHANGE IN CONTROL

     Upon a Change in Control, the current Performance Cycle shall immediately end and all vested Units (including Units that vest pursuant to Section 9.3(b)) shall be paid in cash to Participants based on a value of one hundred fifty dollars ($150) per Unit. This payment will be reduced to reflect any interim benefit payments made in accordance with Section 9.5(b)(ii) and shall be made (i) in a lump sum in cash that is in lieu of any otherwise applicable form and time of payment under the Plan and (ii) within ten (10) days after the Change in Control.

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9.8   UNFUNDED OBLIGATION

     Any amounts (deferred or otherwise) to be paid to Participants pursuant to the Plan are unfunded obligations. Neither the Company nor any Subsidiary is required to segregate any monies from its general funds, to create any trusts or to make any special deposits with respect to this obligation. Beneficial ownership of any investments, including trust investments which the Company may make to fulfill this obligation, shall at all times remain in the Company. Any investments and the creation or maintenance of any trust or any Participant account shall not create or constitute a trust or a fiduciary relationship between the Plan Administrator, the Management Committee, the Company or any Subsidiary and a Participant, or otherwise create any vested or beneficial interest in any Participant or the Participant’s Beneficiary or the Participant’s creditors in any assets of the Company or its Subsidiaries whatsoever. The Participants shall have no claim against the Company for any changes in the value of any assets which may be invested or reinvested by the Company with respect to the Plan.

9.9   DESIGNATION OF BENEFICIARY

     The designation of a Beneficiary shall be on a form provided by the Management Committee, executed by the Participant (with the consent of the Participant’s spouse, if required by the Management Committee for reasons of community property or otherwise), and delivered to the Management Committee. A Participant may change his or her Beneficiary designation at any time. A designation by a Participant under the Predecessor Plan shall remain in effect under the Plan for any Performance Units unless such designation is revoked or changed under the Plan. If no Beneficiary is designated, if the designation is ineffective, or if the Beneficiary dies before the balance of a Participant’s account is paid, the balance shall be paid to the Participant’s spouse, or if there is no surviving spouse, to the Participant’s lineal descendants, pro rata, or if there is no surviving spouse or any lineal descendant, to the Participant’s estate. Notwithstanding the foregoing, however, a Participant’s Beneficiary shall be determined under applicable state law if such state law does not recognize Beneficiary designations under plans of this sort and is not preempted by laws which recognize the provisions of this Section 9.9.

SECTION 10 RESTRICTED STOCK

     10.1 Subject to Sections 5.2 and 5.4, Restricted Stock (including Performance Restricted Stock) may be granted to Participants in such number and at such times during the term of the Plan as the Plan Administrator shall determine, the Plan Administrator taking into account the duties of the respective Participants, their present and potential contributions to the success of the Company, and such other factors as the Plan Administrator shall deem relevant in accomplishing the purposes of the Plan. The granting of Restricted Stock shall take place when the Plan Administrator by resolution, written consent or other appropriate action determines to grant such Restricted Stock to a particular Participant. Each grant shall be evidenced by a written instrument delivered by

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or on behalf of the Company containing provisions not inconsistent with the Plan. The Participant receiving a grant of Restricted Stock shall be recorded as a stockholder of the Company. Each Participant who receives a grant of Restricted Stock shall have all the rights of a stockholder with respect to such shares (except as provided in the restrictions on transferability), including the right to vote the shares and receive dividends and other distributions; provided, however, that no Participant awarded Restricted Stock shall have any right as a stockholder with respect to any shares subject to the Participant’s Restricted Stock grant prior to the date of issuance to the Participant of a certificate or certificates for such shares.

     10.2 Notwithstanding any other provision to the contrary in this Section 10, before Performance Restricted Stock can be granted or vested, as applicable, the Plan Administrator shall:

     (a) Determine the Performance Goals applicable to the particular Performance Period; and

     (b) Certify in writing that such Performance Goals for a particular Performance Period have been attained.

     10.3 A grant of Restricted Stock shall entitle a Participant to receive, on the date or dates designated by the Plan Administrator, upon payment to the Company of the par value of the Common Stock in a manner determined by the Plan Administrator, the number of shares of Common Stock selected by the Plan Administrator. The Plan Administrator may require, under such terms and conditions as it deems appropriate or desirable, that the certificates for Restricted Stock delivered under the Plan may be held in custody by a bank or other institution, or that the Company may itself hold such shares in custody until the Restriction Period (as defined in Section 10.4) expires or until restrictions thereon otherwise lapse, and may require, as a condition of any issuance of Restricted Stock that the Participant shall have delivered a stock power endorsed in blank relating to the shares of Restricted Stock.

     10.4 During a period of years following the date of grant, as determined by the Plan Administrator, which shall in no event be less than one (1) year (the “Restriction Period”), the Restricted Stock may not be sold, assigned, transferred, pledged, hypothecated or otherwise encumbered or disposed of by the recipient, except in the event of death or Permanent Disability, the transfer to the Company as provided under the Plan or the Plan Administrator’s waiver or modification of such restrictions in the agreement evidencing the grant of Restricted Stock, or by resolution of the Plan Administrator adopted at any time.

     10.5 Except as provided in Section 10.6 or 10.7, if a Participant terminates employment with the Company for any reason before the expiration of the Restriction Period, all shares of Restricted Stock still subject to restriction shall be forfeited by the Participant to the Company. In addition, in the event of any attempt by the Participant to

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sell, exchange, transfer, pledge or otherwise dispose of shares of Restricted Stock in violation of the terms of the Plan, such shares shall be forfeited to the Company.

     10.6 The Restriction Period for any Participant shall be deemed to end and all restrictions on shares of Restricted Stock shall lapse, upon the Participant’s death or Permanent Disability or any termination of employment determined by the Plan Administrator to end the Restriction Period.

     10.7 The Restriction Period for any Participant shall be deemed to end and all restrictions on shares of Restricted Stock shall terminate immediately upon a Change in Control.

     10.8 When the restrictions imposed by Section 10.4 expire or otherwise lapse with respect to one or more shares of Restricted Stock, the Company shall deliver to the Participant (or the Participant’s legal representative, Beneficiary or heir) one (1) share of Common Stock for each share of Restricted Stock. At that time, the agreement referred to in Section 10.1, as it relates to such shares, shall be terminated.

     10.9 Subject to Section 10.3 (and Section 10.2 in the case of Performance Restricted Stock), a Participant entitled to receive Restricted Stock under the Plan shall be issued a certificate for such shares. Such certificate shall be registered in the name of the Participant, and shall bear an appropriate legend reciting the terms, conditions and restrictions, if any, applicable to such shares and shall be subject to appropriate stop-transfer orders.

SECTION 11 REGULATORY APPROVALS AND LISTING

     11.1 The Company shall not be required to issue any certificate for shares of Common Stock upon the exercise of an option or a stock appreciation right granted under the Plan, with respect to a grant of Restricted Stock or Common Stock awarded as payment of vested Units prior to:

     (a) obtaining any approval or ruling from the Securities and Exchange Commission, the Internal Revenue Service or any other governmental agency which the Company, in its sole discretion, shall determine to be necessary or advisable;

     (b) listing of such shares on any stock exchange on which the Common Stock may then be listed; or

     (c) completing any registration or other qualification of such shares under any federal or state laws, rulings or regulations of any governmental body which the Company, in its sole discretion, shall determine to be necessary or advisable.

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     All certificates for shares of Common Stock delivered under the Plan shall also be subject to such stop-transfer orders and other restrictions as the Plan Administrator may deem advisable under the rules, regulations and other requirements of the Securities and Exchange Commission, any stock exchange upon which Common Stock is then listed and any applicable federal or State securities laws, and the Plan Administrator may cause a legend or legends to be placed on any such certificates to make appropriate reference to such restrictions. The foregoing provisions of this paragraph shall not be effective if and to the extent that the shares of Common Stock delivered under the Plan are covered by an effective and current registration statement under the Securities Act of 1933, as amended, or if and so long as the Plan Administrator determines that application of such provisions as no longer required or desirable. In making such determination, the Plan Administrator may rely upon an opinion of counsel for the Company.

SECTION 12 EFFECTIVE DATE AND TERM OF PLAN

     The Plan was originally adopted by the Board effective as of January 13, 1995, and approved by the Company’s stockholders on March 16, 1995. The Board amended and restated the Plan effective as of August 1, 1998, in connection with the reorganization of the Company into a holding company structure whereby El Paso Energy Corporation became the publicly held company and El Paso Natural Gas Company became a wholly owned subsidiary. This Plan was assumed by El Paso Energy Corporation pursuant to an Assignment and Assumption Agreement effective as of August 1, 1998, by and between El Paso Energy Corporation and El Paso Natural Gas Company. Options, limited stock appreciation rights, stock appreciation rights, Restricted Stock and Performance Units may be granted pursuant to the Plan from time to time within the period commencing upon adoption of the Plan by the Board of Directors and ending ten (10) years after the earlier of such adoption and the approval of the Plan by the stockholders. Options, limited stock appreciation rights, stock appreciation rights, Restricted Stock and Performance Units theretofore granted may extend beyond that date and the terms and conditions of the Plan shall continue to apply thereto and to shares of Common Stock acquired thereunder. To the extent required for compliance with Rule 16b-3, shares of Common Stock underlying options, limited stock appreciation rights, stock appreciation rights, Restricted Stock and Common Stock granted, subject to stockholder approval of the Plan, to Section 16 Insiders may not be sold until a date at least six (6) months after the date such stockholder approval is obtained, and stock appreciation rights that are granted subject to stockholder approval of the Plan to Section 16 Insiders may not be exercised for cash until a date at least six (6) months after the date such stockholder approval is obtained.

El Paso Energy Corporation
1995 Omnibus Compensation Plan Page 27

SECTION 13 GENERAL PROVISIONS

     13.1 Nothing contained in the Plan, or in any option, limited stock appreciation right, stock appreciation right, Restricted Stock or Performance Unit granted pursuant to the Plan, shall confer upon any employee any right with respect to continuance of employment by the Company or a Subsidiary, nor interfere in any way with the right of the Company or a Subsidiary to terminate the employment of such employee at any time with or without assigning any reason therefor.

     13.2 Grants, vesting or payment of stock options, limited stock appreciation rights, stock appreciation rights, Restricted Stock or Performance Units shall not be considered as part of a Participant’s salary or used for the calculation of any other pay, allowance, pension or other benefit unless otherwise permitted by other benefit plans provided by the Company or its Subsidiaries, or required by law or by contractual obligations of the Company or its Subsidiaries.

     13.3 The right of a Participant or Beneficiary to the payment of any compensation under the Plan may not be assigned, transferred, pledged or encumbered, nor shall such right or other interests be subject to attachment, garnishment, execution or other legal process.

     13.4 Leaves of absence for such periods and purposes conforming to the personnel policy of the Company, or of its Subsidiaries, as applicable, shall not be deemed terminations or interruptions of employment, unless a Participant commences a leave of absence from which he or she is not expected to return to active employment with the Company or its Subsidiaries. The foregoing notwithstanding, with respect to Incentive Stock Options, employment shall not be deemed to continue beyond the first ninety (90) days of such leave unless the Participant’s reemployment rights are guaranteed by statute or contract.

     13.5 In the event a Participant is transferred from the Company to a Subsidiary, or vice versa, or is promoted or given different responsibilities, the stock options, limited stock appreciation rights, stock appreciation rights, Restricted Stock and Performance Units granted to the Participant prior to such date shall not be affected.

     13.6 The Plan shall be construed and governed in accordance with the laws of the State of Texas, except that it shall be construed and governed in accordance with applicable federal law in the event that such federal law preempts state law.

     13.7 Appropriate provision shall be made for all taxes required to be withheld in connection with the exercise, grant or other taxable event with respect to options, limited stock appreciation rights, stock appreciation rights, Restricted Stock and Performance Units under the applicable laws or regulations of any governmental authority, whether federal, state or local and whether domestic or foreign. Unless otherwise provided in the grant, a Participant is permitted to deliver shares of Common

El Paso Energy Corporation
1995 Omnibus Compensation Plan Page 28

Stock (including shares acquired pursuant to the exercise of an option or stock appreciation right other than the option or stock appreciation right currently being exercised, to the extent permitted by applicable regulations) for payment of withholding taxes on the exercise of an option, stock appreciation right, or limited stock appreciation right, upon the grant or vesting of Restricted Stock or upon the payout of Performance Units. At the election of the Plan Administrator or, subject to approval of the Plan Administrator at its sole discretion, at the election of a Participant, shares of Common Stock may be withheld from the shares issuable to the Participant upon the exercise of an option or stock appreciation right, upon the vesting of the Restricted Stock or upon the payout of Performance Units to satisfy tax withholding obligations. The Fair Market Value of Common Stock as delivered pursuant to this Section 13.7 shall be valued as of the day prior to delivery, and shall be calculated in accordance with Section 2.9. The withholding of shares of Common Stock to pay tax obligations in connection with the exercise of an option or stock appreciation right, the vesting of Restricted Stock or the payout of Performance Units by a Section 16 Insider must be approved by the Plan Administrator and must occur (i) pursuant to an irrevocable election made six (6) months in advance of the transaction, (ii) during the period beginning on the third business day following the date of release for publication of the quarterly or annual summary statements of sales and earnings of the Company and ending on the twelfth business day following such date, or (iii) otherwise in accordance with the provisions of Rule 16b-3 and interpretations thereunder. In the event Rule 16b-3 is amended or interpreted to permit shares of Common Stock to be withheld to pay tax obligations outside the periods described in clause (i) or (ii) of the preceding sentence, or without Plan Administrator approval, the Plan Administrator may determine that such provisions shall no longer apply to Section 16 Insiders.

     Any Participant that makes a Section 83(b) election under the Code shall, within ten (10) days of making such election, notify the Company in writing of such election and shall provide the Company with a copy of such election form filed with the Internal Revenue Service.

     Tax advice should be obtained by the Participant prior to the Participant’s (i) entering into any transaction under or with respect to the Plan, (ii) designating or choosing the times of distributions under the Plan, or (iii) disposing of any shares of Common Stock issued under the Plan.

SECTION 14 COMPLIANCE WITH RULE 16b-3 AND SECTION 162(m)

     The Company’s intention is that, so long as any of the Company’s equity securities are registered pursuant to Section 12(b) or 12(g) of the Exchange Act, with respect to awards granted to or held by Section 16 Insiders, the Plan shall comply in all respects with Rule 16b-3 and Section 162(m) and, if any Plan provision is later found not to be in compliance with Rule 16b-3 or Section 162(m), that provision shall be deemed modified as necessary to meet the requirements of Rule 16b-3 and Section 162(m).

El Paso Energy Corporation
1995 Omnibus Compensation Plan Page 29

Notwithstanding the foregoing, and subject to Section 5.2, the Plan Administrator may grant or vest Restricted Stock that may not be in compliance with Section 162(m).

     Notwithstanding anything in the Plan to the contrary, the Board of Directors, in its absolute discretion, may bifurcate the Plan so as to restrict, limit or condition the use of any provision of the Plan to Participants who are Section 16 Insiders without so restricting, limiting or conditioning the Plan with respect to other Participants.

SECTION 15 AMENDMENT, TERMINATION OR DISCONTINUANCE
OF THE PLAN

     15.1 Subject to the Board of Directors and Section 15.2, the Plan Administrator may from time to time make such amendments to the Plan as it may deem proper and in the best interest of the Company without further approval of the stockholders of the Company, including, but not limited to, any amendment necessary to ensure that the Company may obtain any regulatory approval referred to in Section 11; provided, however, that no change in any option, limited stock appreciation right, stock appreciation right, Restricted Stock or Performance Unit theretofore granted may be made without the consent of the Participant which would impair the right of the Participant to acquire or retain Common Stock or cash that the Participant may have acquired as a result of the Plan.

     15.2 To the extent required for compliance with applicable law or regulation, including Rule 16b-3 and Section 162(m), the Plan Administrator and the Board of Directors may not amend the Plan without the approval of the stockholders of the Company to

     (a) materially increase the number of shares, rights or Units that may be issued under the Plan to Section 16 Insiders;

     (b) with respect to Incentive Stock Options and any related stock appreciation rights (whether limited or not), change the description of the Participants or class of participants eligible for participation in the Plan, or, with respect to all other grants under the Plan, materially modify the requirements as to eligibility for participation in the Plan to add a class of Section 16 Insiders; or

     (c) otherwise materially increase the benefits accruing to the Participants under the Plan.

     15.3 Grants of Performance Restricted Stock and Performance Units shall not be made under this Plan unless the material terms, as defined by Section 162(m), of the Performance Goal(s) under which an award is to be paid have been disclosed and subsequently approved by the Company’s stockholders in accordance with Section 162(m).

El Paso Energy Corporation
1995 Omnibus Compensation Plan Page 30

     15.4 The Board of Directors may at any time suspend the operation of or terminate the Plan with respect to any shares of Common Stock, rights or Performance Units which are not at that time subject to option, limited stock appreciation right, stock appreciation right or grant of Restricted Stock, or with respect to any Performance Units not yet granted under Section 9.

El Paso Energy Corporation
1995 Omnibus Compensation Plan Page 31

     IN WITNESS WHEREOF, the Company has caused the Plan to be amended and restated effective as of August 1, 1998.

EL PASO ENERGY CORPORATION
By	/s/ JOEL RICHARDS III
Title: Executive Vice President

ATTEST:

By	/s/ DAVID L. SIDDALL
Title: Corporate Secretary

El Paso Energy Corporation
1995 Omnibus Compensation Plan Page 32

EX-10.I.1

EXHIBIT 10.I.1

AMENDMENT NO. 1 TO THE
1995 OMNIBUS COMPENSATION PLAN

     Pursuant to Section 15.1 of the El Paso Energy Corporation 1995 Omnibus Compensation Plan, as amended and restated (the “Plan”), the Plan is hereby amended as follows, effective December 3, 1998:

The following subsection (k) shall be added to Section 6.4 to read as follows:

     “(k) Deferral Election

     A Participant may elect irrevocably (at a time and in a manner determined by the Plan Administrator or the Company, as appropriate) at any time prior to exercising an option granted under the Plan that issuance of shares of Common Stock upon exercise of such option and/or associated stock appreciation right shall be deferred until a pre-specified date in the future or until the Participant ceases to be employed by the Company or any of its Subsidiaries, as elected by the Participant. After the exercise of any such option and prior to the issuance of any deferred shares, the number of shares of Common Stock issuable to the Participant shall be credited to the deferred stock account (or such other account(s) as the Management Committee shall deem necessary and appropriate) under a memorandum deferred account established pursuant the Company’s then-existing Deferred Compensation Plan (as it may be further amended) (the “Deferred Compensation Plan”), and any dividends or other distributions paid on the Common Stock (or its equivalent) shall be deemed reinvested in additional shares of Common Stock (or its equivalent) until all credited deferred shares shall become issuable pursuant to the Participant’s election, unless the Management Committee of the Deferred Compensation Plan shall otherwise determine.”

Section 9.5(c) is amended to read as follows:

     “(c) Form of Payment

     A Participant or a Participant’s Beneficiary shall be entitled to receive from the Company a benefit payment as provided pursuant to Sections 9.5(b)(i) or 9.5(b)(ii), as applicable, equal to the product of the Adjusted Value and the number of vested Units of a Participant. Such payment shall be made as soon as practicable following the applicable Valuation Date in accordance with this Section 9.5(c).

     Except as provided in Sections 9.5(d) and 9.7 (or unless the Plan Administrator otherwise determines at any time that the form of payment should be changed), benefit payments made to a Participant pursuant to this Section 9, shall be made as follows:

(i) Participants employed by the Company holding the position of Chairman of the Board, President or Chief Executive Officer and Participants employed by Company Subsidiaries holding equivalent positions, but not necessarily the same title, shall receive their Performance Unit payout as follows:

(A) 50% (fifty percent) in cash and

(B) 50% (fifty percent) in Common Stock.

(ii) Participants employed by the Company holding the position of Vice Chairman of the Board, Chief Operating Officer, or Executive Vice President and Participants employed by Company Subsidiaries holding equivalent positions, but not necessarily the same title, shall receive their Performance Unit payout as follows:

(A) 60% (sixty percent) in cash and

(B) 40% (forty percent) in Common Stock.

(iii) Participants employed by the Company holding the position of Senior Vice President and Participants employed by Company Subsidiaries holding equivalent positions, but not necessarily the same title, shall receive their Performance Unit payout as follows:

(A) 75% (seventy-five percent) in cash and

(B) 25% (twenty-five percent) in Common Stock.”

The following Section 10.10 shall be added to read as follows:

     “10.10 A Participant may elect irrevocably (at a time and in the manner determined by the Plan Administrator or the Company, as appropriate), prior to vesting of Restricted Stock, that the Participant relinquishes any and all rights in the shares of Restricted Stock in exchange for an interest in the Deferred Compensation Plan and receipt of such shares shall be deferred until a pre-specified date in the future or until the Participant ceases to be employed by the Company or any of its Subsidiaries, as elected by the Participant. At the time the restrictions lapse on the shares of Restricted Stock (as specified at the time of grant, or otherwise if changed by the Plan Administrator), the number of shares of Common Stock issuable to the Participant shall be credited to the deferred stock account (or such other account(s) as the Management Committee shall deem necessary and appropriate) under a memorandum deferred account established pursuant to the Deferred Compensation Plan, and any dividends or other distributions paid on the Common Stock (or its equivalent) shall be deemed reinvested in additional shares of Common Stock (or its equivalent) until all credited deferred shares shall become issuable pursuant to the Participant’s election, unless the Management Committee of the Deferred Compensation Plan shall otherwise determine.”

The first sentence of Section 13.7 is hereby deleted in its entirety and replaced with the following sentence:

“Appropriate provision shall be made for all taxes required to be withheld in connection with the exercise, grant or other taxable event with respect to options, limited stock appreciation rights, stock appreciation rights, Restricted Stock and Performance Units under the applicable laws and regulations of any governmental authority, whether federal, state or local and whether domestic or foreign, including, but not limited to, the required withholding of a sufficient number of shares of Common Stock otherwise issuable to a Participant to satisfy the said required minimum tax withholding obligations.”

     IN WITNESS WHEREOF, the Company has caused this amendment to be duly executed on this 3rd day of December, 1998.

EL PASO ENERGY CORPORATION
By:	/s/ Joel Richards III
	Joel Richards III
	Executive Vice President

Attest:

/s/ David L. Siddall

Corporate Secretary

EX-10.I.2

Exhibit 10.I.2

AMENDMENT NO. 2 TO THE
1995 OMNIBUS COMPENSATION PLAN

     Pursuant to Section 15.1 of the El Paso Energy Corporation 1995 Omnibus Compensation Plan, as amended and restated (the “Plan”), the Plan is hereby amended as follows, effective January 20, 1999:

The following paragraph shall be added as the last paragraph to Section 6.4(d) to read as follows:

     “Notwithstanding any other provision in this Plan to the contrary and unless the Plan Administrator shall otherwise determine, in the event of a “cashless” exercise, and for that purpose only under this Plan, a Participant’s compensation shall be equal to the difference between the actual sales price received for the underlying Common Stock and the Option Price. For all other purposes under this Plan, the Fair Market Value shall be the value against which compensation is determined.”

The following sentence shall be added as the last sentence to Section 6.4(e) to read as follows:

“In addition, the Plan Administrator may require that a Participant who wants to effectuate a “cashless” exercise of options be required to sell the shares of Common Stock acquired in the associated exercise to the Company, or in the open market through the use of a broker selected by the Company, at such price and on such terms as the Plan Administrator may determine at the time of grant, or otherwise.”

Section 6.4(f) is hereby deleted in its entirety and replaced with the following:

     “(f) Nontransferability of Options

     Options granted under the Plan and the rights and privileges conferred thereby shall not be subject to execution, attachment or similar process and may not be transferred, assigned, pledged or hypothecated in any manner (whether by operation of law or otherwise) other than by will or by the applicable laws of descent and distribution. Notwithstanding the foregoing and only as provided by the Plan Administrator or the Company, as applicable, Nonqualified Options may be transferred to a Participant’s immediate family members, directly or indirectly or by means of a trust, corporate entity or partnership (a person who thus acquires this option by such transfer, a “Permitted Transferee”). A transfer of an option may only be effected by the Company at the request of the Participant and shall become effective upon the Permitted Transferee agreeing to such terms as the Plan Administrator may require and only when recorded in the Company’s record of outstanding options. In the event an option is transferred as contemplated hereby, the option may not be subsequently transferred by the Permitted Transferee except

5

a transfer back to the Participant or by will or the laws of descent and distribution. A transferred option may be exercised by a Permitted Transferee to the same extent as, and subject to the same terms and conditions as, the Participant (except as otherwise provided herein), as if no transfer had taken place. As used herein, “immediate family” shall mean, with respect to any person, such person’s child, stepchild, grandchild, parent, stepparent, grandparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law, sister-in-law, and shall include adoptive relationships. In the event of exercise of a transferred option by a Permitted Transferee, any amounts due to (or to be withheld by) the Company upon exercise of the option shall be delivered by (or withheld from amounts due to) the Participant, the Participant’s estate or the Permitted Transferee, in the reasonable discretion of the Company.

     In addition, to the extent permitted by applicable law and Rule 16b-3, the Plan Administrator may permit a recipient of a Nonqualified Option to designate in writing during the Participant’s lifetime a Beneficiary to receive and exercise the Participant’s Nonqualified Options in the event of such Participant’s death (as provided in Section 6.4(i)). A designation by a Participant under the Company’s Omnibus Compensation Plan dated as of January 1, 1992 (the “Predecessor Plan”) shall remain in effect under the Plan for any options unless such designation is revoked or changed under the Plan. Except as otherwise provided for herein, if any Participant attempts to transfer, assign, pledge, hypothecate or otherwise dispose of any option under the Plan or of any right or privilege conferred thereby, contrary to the provisions of the Plan or such option, or suffers the sale or levy or any attachment or similar process upon the rights and privileges conferred hereby, all affected options held by such Participant shall be immediately forfeited.”

     IN WITNESS WHEREOF, the Company has caused this amendment to be duly executed on this 20th day of January, 1999.

EL PASO ENERGY CORPORATION
By:	/s/ Joel Richards III
	Joel Richards III
	Executive Vice President

Attest:

/s/ David L. Siddall

Corporate Secretary

EX-10.L.1

EXHIBIT 10.L.1

AMENDMENT NO. 2 TO THE
EL PASO CORPORATION
SUPPLEMENTAL BENEFITS PLAN

     Pursuant to Section 6.7 of the El Paso Corporation Supplemental Benefits Plan, Amended and Restated effective as of December 7, 2001, as amended (the “Plan”), the Plan is hereby amended as follows, effective June 1, 2004:

     Section 5.4(a) is hereby deleted in its entirety and replaced with the following:

“(a) Supplemental Pension Benefit Payments. The payment of any supplemental pension benefits pursuant to Section 5.1 owed to a Participant (or his or her Surviving Spouse) shall be made in lump sum as soon as practicable after the Participant’s termination of employment with the Employer unless the Participant made a valid irrevocable election to receive such payment in a form other than a lump sum payment prior to the effective date of this Amendment. The amount of the payment under this subparagraph 5.4(a) shall be determined pursuant to Section 5.5; provided, however, no such payment shall be required to be made to the Participant if the amount of the payment the Participant is entitled to receive for supplement pension benefits under this Plan is less than $100.”

     Section 5.4(b) is hereby deleted in its entirety and replaced with the following:

“(b) Supplemental RSP Benefit Payments. The payment of any supplemental RSP benefits pursuant to Section 5.2 owed to a Participant (or his or her Beneficiary) shall be made in a lump sum as soon as practicable after the Participant’s termination of employment with the Employer and shall be in an amount equal to the Participant’s ledger account balance at the time of such payment; provided, however, no such payment shall be required to be made to the Participant if the amount of the payment the Participant is entitled to receive for supplemental RSP benefits under this Plan is less than $100.”

     Section 5.5 is hereby deleted in its entirety and replaced with the following:

“5.5 Determination of Supplemental Pension Benefit Payments

     Subject to Section 5.6 and 5.7, the amount of a payment of supplemental pension benefits pursuant to Section 5.1 to a Participant (or his or her Surviving Spouse in the event of the Participant’s termination of employment on account of death) shall be determined by calculating the benefit according to the terms of the Pension Plan as a single life annuity.”

     IN WITNESS WHEREOF, the Company has caused this amendment to be duly executed on this 1st day of June, 2004.

EL PASO CORPORATION
By:	/s/ Susan B. Ortenstone
	Susan B. Ortenstone
	Its Senior Vice President, Human Resources

Attest:

/s/ David L. Siddall

Corporate Secretary

EX-10.M

1

EXHIBIT 10.M

EL PASO ENERGY CORPORATION

SENIOR EXECUTIVE SURVIVOR
BENEFIT PLAN

AMENDED AND RESTATED EFFECTIVE AS OF AUGUST 1, 1998

TABLE OF CONTENTS

ARTICLE I	NAME AND PURPOSE	1
1.1	Name of the Plan	1
1.2	Purpose	1
1.3	Scope of the Plan	1
ARTICLE II	ADMINISTRATION	1
2.1	Administrator	1
2.2	The Administrator’s Powers and Duties	1
ARTICLE III	PARTICIPATION	2
3.1	Participation in the Plan	2
ARTICLE IV	SURVIVOR’S BENEFIT	3
4.1	Pre-Retirement Survivor’s Benefit	3
4.2	Cash-Out of Retirement Survivor’s Benefit	3
4.3	Annual Salary	3
4.4	No Duplicate Coverage	3
ARTICLE V	PAYMENT OF BENEFITS	4
5.1	Payment of Survivor’s Benefit	4
5.2	Beneficiary	4
5.3	Proof of Death or Disability	4
5.4	Payment to Person Under a Disability	4
5.5	Duration of Coverage	5
	(a)      Active Employment	5
	(b)      Disability	5
	(c)      All Other Terminations	5
5.6	Payment by the Company	5
ARTICLE VI	FUNDING THE PLAN	5
6.1	Unfunded Obligation	5
6.2.	Individual Policies of Insurance	6
ARTICLE VII	MISCELLANEOUS	6
7.1	Non-Assignability	6
7.2	Claims Procedure	6
7.3	Liability of Administrator	7
7.4	Adoption of Plan	7
7.5	Amendments, Suspension or Termination	7
7.6	Applicable State Law	7
7.7	No Guarantee of Employment	7
7.8	No Examination or Accounting	8
7.9	Other Terms and Conditions	8
7.10	Effective Date of Plan	8

El Paso Energy Corporation
Senior Executive Survivor Benefit Plan -i- Table of Contents

EL PASO ENERGY CORPORATION
SENIOR EXECUTIVE SURVIVOR BENEFIT PLAN
AMENDED AND RESTATED EFFECTIVE AS OF AUGUST 1, 1998

ARTICLE I NAME AND PURPOSE

1.1 NAME OF THE PLAN

     The name of the Plan is the “El Paso Energy Corporation Senior Executive Survivor Benefit Plan.”

1.2 PURPOSE

     The purpose of the Plan is to provide survivor benefits for certain senior executives of El Paso Energy Corporation (the “Company”) and its designated subsidiaries to secure the good will, loyalty and efficiency of the covered executives, and to attract and retain in the employ of the Company persons of outstanding competence.

1.3 SCOPE OF THE PLAN

     The Plan is intended to be an unfunded or an insured welfare plan maintained by the Company for the purpose of providing benefits for a select group of management employees who are highly compensated, pursuant to Section 104(a)(3) of the Employee Retirement Income Security Act of 1974 (ERISA) and Labor Department regulation Section 2520.104-24 thereunder, or any statutory or regulatory provisions that may hereafter replace such sections. No Participant shall be required or permitted to make contributions to the Plan.

ARTICLE II ADMINISTRATION

2.1 ADMINISTRATOR

     The Executive Vice President-Human Resources of the Company or the officer holding a position of comparable responsibilities shall be the administrator (the “Administrator”) of the Plan.

2.2 THE ADMINISTRATOR’S POWERS AND DUTIES

     The Administrator shall have such powers and duties as may be necessary to discharge his functions hereunder including, but not limited to, the following:

     (a) to make such rules and regulations as may be required to carry out the provisions of the Plan or to facilitate the operations of the Plan;

El Paso Energy Corporation
Senior Executive Survivor Benefit Plan Page 1

     (b) to construe and interpret the Plan, to decide all questions of eligibility and to determine the amount, manner and time of payment of any benefits hereunder;

     (c) to make a determination as to the right of any person to a benefit;

     (d) to obtain from the Company and from Participants such information as shall be necessary for the proper administration of the Plan and, when appropriate, to furnish such information to other persons entitled thereto;

     (e) to purchase group term or individual policies of life insurance covering the Participants to fund the obligation of the Company pursuant to the terms of this Plan;

     (f) to authorize one or more agents to make any payment on behalf of the Company, to appoint agents and clerks, and to employ such professional services, including legal, medical, accounting and actuarial, as may be required in carrying out the provisions of the Plan; and

     (g) to keep all such books of account, records and other data as may be necessary for the proper administration of the Plan.

All determinations and actions by the Administrator pursuant to the terms of the Plan and any rules or regulations thereunder shall be binding upon all Participants and their Beneficiaries.

ARTICLE III PARTICIPATION

3.1 PARTICIPATION IN THE PLAN

     Executives of the Company and its subsidiaries who possess an employee classification of level D or higher will be eligible to participate in the Plan (the “Participants”). Generally, Participants will be the Chairman of the Board, President and Chief Executive officer, the Vice Chairman and the Senior Officers of the Company and certain of its operating subsidiaries reporting directly to them who have the principal responsibility for the management, direction and success of the Company as a whole or particular business unit thereof. However, the Administrator may, at his discretion and solely for purposes of determining eligibility to be a Participant, adjust an employee’s level classification to ensure that level classifications are determined in a uniform manner among the Company and its subsidiaries. Any participant in the Burlington Resources Inc. Senior Executive Survivor Benefit Plan (“BRI Plan”) on the day immediately preceding the effective date of this Plan, who is an employee of the Company, shall become a Participant of this Plan on the effective date and shall immediately cease participation in the BRI Plan.

El Paso Energy Corporation
Senior Executive Survivor Benefit Plan Page 2

ARTICLE IV SURVIVOR’S BENEFIT

4.1   PRE-RETIREMENT SURVIVOR’S BENEFIT

     If a Participant dies while employed by the Company or a subsidiary, the Company shall pay to the Participant’s Beneficiary a monthly survivor’s benefit (“Survivor’s Benefit”) for 30 months. The monthly payment shall be calculated as follows:

     (a) the amount necessary to pay, after payment of Federal income tax, (i) two and one-half times the Participant’s Annual Salary less (ii) the amount of any Cash-Out that the Participant previously received (as described in Section 4.2), and less (iii) $50,000, which may be paid as a group life insurance benefit;

     (b) divided by thirty.

In calculating the amount by which the Survivor’s Benefit will be increased to adjust for Federal income tax, the highest applicable marginal rate for the year in which the payments begin shall be assumed to apply, and the Beneficiary shall be assumed to pay tax on the complete benefit in the year monthly payments commence, rather than upon receipt of each monthly payment when such amounts are actually taxable. If the amount so calculated is zero or less, no payment shall be made to the Participant’s Beneficiary under this Plan.

4.2   CASH-OUT OF RETIREMENT SURVIVOR’S BENEFIT

     Each executive who was a participant on December 1, 1988, in the BRI Plan has received the actuarial present value of the Retirement Survivor’s Benefit offered by the BRI Plan prior to December 1, 1988 (the “Cash-out”). No further Retirement Survivor’s Benefit shall be paid by this Plan.

4.3   ANNUAL SALARY

     For purposes of this Plan, a Participant’s Annual Salary shall mean the annual salary being paid to him by the Company or subsidiary at the time of his death, including amounts contributed by his employer on behalf of the Participant to a deferred compensation plan, or any salary reduction plan meeting the requirements of Section 401(k) of the Internal Revenue Code of 1986, as amended, and the regulations promulgated thereunder from time to time, or any statutory provision that may hereafter replace such section, but excluding payments to the Participant under any stock option, employee stock ownership, bonus, performance share unit, or other incentive plans or extra, vacation, or added compensation or benefits of any kind or nature.

4.4   NO DUPLICATE COVERAGE

Participants in this Plan shall not be eligible to receive life insurance benefits under any group term life insurance policies (other than travel and accident policies) which are purchased by the Company or its subsidiaries to cover employees who are not eligible to participate in this Plan.

El Paso Energy Corporation
Senior Executive Survivor Benefit Plan Page 3

ARTICLE V PAYMENT OF BENEFITS

5.1   PAYMENT OF SURVIVOR’S BENEFIT

     The Survivor’s Benefit shall be paid commencing on the first day of the month following the Participant’s death, or as soon thereafter as is practicable, in thirty monthly installments. The unpaid balance of the Survivor’s Benefit shall not bear interest. The Administrator may, in his sole discretion, arrange for a lump sum payment to the Participant’s Beneficiary of the unpaid balance of the Survivor’s Benefit, commuted to a present value based on a reasonable discount rate to be determined by the Administrator.

5.2   BENEFICIARY

     The Beneficiary shall be the person or persons designated from time to time by a Participant, upon a form made available by the Administrator for such purpose or in such form satisfactory to the Administrator, to receive distributions from this Plan in the event of the Participant’s death. Any such person or persons designated by the Participant under the BRI Plan shall be the Beneficiary under this Plan until such designation is revoked or changed. In the event that no such designation shall have been made or the person so designated shall have predeceased the Participant or shall have died before the Benefit has been fully paid, the remaining balance of such Benefit shall be paid in equal shares to the first surviving class of the following classes of preference beneficiaries: (a) the Participant’s spouse, (b) the Participant’s surviving children, (c) the Participant’s parents, (d) the Participant’s surviving brothers and sisters, or (e) the Participant’s executor or administrator. A Participant may at any time change his beneficiary designation by filing prior to such Participant’s death, written notice of such change with the Administrator in the manner set forth in this Section 5.2.

5.3   PROOF OF DEATH OR DISABILITY

     The Administrator may require proof of death or permanent disability of a Participant and evidence of the right of a Beneficiary to receive a Benefit of a deceased Participant.

5.4   PAYMENT TO PERSON UNDER A DISABILITY

     If a Benefit is payable to a minor or incompetent or to a person incapable of handling the disposition of his property, the Administrator may pay such Benefit to the guardian, legal representative or person having the care and custody of such Beneficiary. The Administrator may require proof of incompetency, minority or guardianship as he may deem appropriate prior to distribution of the Benefit. Such distribution shall completely discharge the Administrator and the Company from all liability with respect to such Benefit.

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5.5   DURATION OF COVERAGE

     (a) Active Employment

     A Participant shall remain eligible for the Benefit provided by this Plan so long as he shall remain actively employed by the Company or a subsidiary in an executive position comparable to those described in Section 3.1. Leaves of absence for such periods and purposes consented to by the Company or its subsidiaries, as applicable, shall not be deemed termination of employment.

     (b) Disability

     A Participant who becomes permanently disabled while employed by the Company or a subsidiary for purposes of this Plan shall be deemed to remain in the active employment of his employer while under such disability until such Participant retires under a pension plan sponsored by the Company or a subsidiary or until he has attained age sixty-five (65), whichever date is the first to occur. At such time such disabled Participant shall be deemed to be a retired Participant for purposes of this Plan and, therefore, no longer eligible for any Survivors Benefit provided by this Plan. A Participant shall be considered permanently disabled when he is eligible to receive benefits under the El Paso Energy Corporation Long Term Disability Income Plan or a plan providing comparable benefits which is sponsored by his Employer.

     (c) All Other Terminations

     A Participant who resigns or whose employment with the Company or any of its subsidiaries is terminated for reasons other than death or permanent disability shall continue to be covered by the Plan for thirty-one (31) days following the date of such termination.

5.6   PAYMENT BY THE COMPANY

     All payments to Participants of the Plan, whether or not they previously participated in the BRI Plan, shall be made by the Company.

ARTICLE VI FUNDING THE PLAN

6.1   UNFUNDED OBLIGATION

     The Survivor’s Benefits to be paid to the Beneficiaries of the Participants pursuant to this Plan are an unfunded obligation of the Company. Nothing herein contained shall require the Company to segregate any monies from its general funds, to create any trust, to make any special deposits, or to purchase any policies of insurance with respect to this obligation. Title to and beneficial ownership of any policies of insurance purchased or funds invested by the Company,

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including the proceeds, income and profits therefrom, which the Company may make to fulfill its obligations under this Plan shall at all times remain in the Company.

6.2   INDIVIDUAL POLICIES OF INSURANCE

     Notwithstanding the provisions of Section 6.1, the Company may fulfill part or all of its obligation to provide Survivor’s Benefits to the Participants by purchasing individual “key man” policies of insurance on one or more of the Participants. Such individual contracts and the proceeds therefrom shall at all times remain the sole property of the Company and the Participants whose lives are insured and their Beneficiaries shall have no ownership rights in such policies or insurance.

ARTICLE VII MISCELLANEOUS

7.1   NON-ASSIGNABILITY OF BENEFITS

     No benefit payable at any time under the Plan shall be subject in any manner to alienation, sale, transfer, assignment, pledge, or encumbrance of any kind. Any attempt to alienate, sell, transfer, assign, pledge, or otherwise encumber any such benefit, whether presently or thereafter payable, shall be void. To the extent permitted by law, no benefits payable under the Plan shall in any manner be subject to garnishment, attachment, execution, or other legal process or be liable for, or subject to the debts or liability of any Participant or Beneficiary.

7.2   CLAIMS PROCEDURE

     Claims for benefits under the Plan shall be filed on forms supplied by the Administrator to:

Administrator
El Paso Energy Corporation
Senior Executive Survivor Benefit Plan
Human Resources Department
El Paso Energy Corporation
1001 Louisiana Street
Houston, Texas 77002

or such other address as may be communicated in writing to the Participants by or at the direction of the Administrator. If any claim for a benefit is wholly or partially denied by the Administrator, the Administrator shall give written notice to the claimant setting forth the specific reasons for the denial in a manner calculated to be understood by the claimant. Any claimant whose request for a benefit is denied in whole or in part may submit a written appeal to the Administrator for a review of the denial. Within sixty (60) days after receipt of such an appeal, the Administrator shall notify the claimant in writing of his decision with respect to the appeal and the specific reasons for the decision. The decision of the Administrator shall be final.

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7.3   LIABILITY OF ADMINISTRATOR

     In connection with any action or determination, the Administrator shall be entitled to rely upon information furnished by the Company or its subsidiaries. To the extent permitted by law, the Company shall indemnify the Administrator against any liability or loss sustained by reasons of any act or failure to act in his administrative capacity, if such act or failure to act does not involve willful misconduct. Such indemnification of the Administrator shall include attorneys’ fees and other costs and expenses reasonably incurred in defense of any action brought against the Administrator by reason of any such act or failure to act.

7.4   ADOPTION OF PLAN

     Any subsidiary which is an affiliate of the Company may be designated by the Company as an Employer for purposes of this Plan. Any Employer may withdraw from participation in the Plan at any time by filing with the Administrator a written notice to that effect prior to the effective date of withdrawal.

7.5   AMENDMENTS, SUSPENSION OR TERMINATION

The Compensation and Nominating Committee of the Board of Directors of the Company or the Administrator shall have the right to amend, modify, suspend, or terminate this Plan at any time. No such amendment, suspension or termination shall adversely affect the right of a Beneficiary to receive a benefit pursuant to the terms of the Plan as the result of the death of a Participant which occurred prior to the date of such change. The Board of Directors amended and restated the Plan effective as of August 1, 1998, in connection with the reorganization of the Company into a holding company structure whereby El Paso Energy Corporation became the publicly held company and El Paso Natural Gas Company became a wholly owned subsidiary. This Plan was assumed by El Paso Energy Corporation pursuant to an Assignment and Assumption Agreement effective as of August 1, 1998, by and between El Paso Energy Corporation and El Paso Natural Gas Company.

7.6   APPLICABLE STATE LAW

     This Plan shall be construed in accordance with the laws of the State of Texas.

7.7   NO GUARANTEE OF EMPLOYMENT

     Nothing contained in this Plan shall be construed as a contract of employment between a Company or a subsidiary and any Participant, or as a right of any Participant to be continued in the employment of his Employer.

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7.8   NO EXAMINATION OR ACCOUNTING

     Neither this Plan nor any action taken thereunder shall be construed as giving any persons the right to an accounting or to examine the books or affairs of the Company.

7.9   OTHER TERMS AND CONDITIONS

     The Company may impose such other lawful terms and conditions on an employee’s participation in this Plan as it shall deem desirable.

7.10   EFFECTIVE DATE OF PLAN

     The Plan shall be effective as of January 1, 1992.

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     IN WITNESS WHEREOF, the Company has caused the Plan to be amended and restated effective as of August 1, 1998.

		EL PASO ENERGY CORPORATION
		By	/s/ Joel Richards III
		Title: Executive Vice President
ATTEST:
By	/s/ David L. Siddall
Title: Corporate Secretary

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EX-10.N

EXHIBIT 10.N

EL PASO ENERGY CORPORATION

KEY EXECUTIVE SEVERANCE

PROTECTION PLAN

AMENDED AND RESTATED EFFECTIVE AS OF AUGUST 1, 1998

TABLE OF CONTENTS

SECTION	1	ESTABLISHMENT OF PLAN	1
SECTION	2	DEFINITIONS	1
	2.1	Base Salary	1
	2.2	Benefits Protection Trust	1
	2.3	Board	2
	2.4	Bonus Amount	2
	2.5	Cause	2
	2.6	Change in Control	3
	2.7	Company	3
	2.8	Effective Date	4
	2.9	Executive Employee	4
	2.10	Good Reason	4
	2.11	Notice of Termination	5
	2.12	Operating Companies	5
	2.13	Participant	5
	2.14	Permanent Disability	5
	2.15	Severance Benefit	5
SECTION	3	ELIGIBILITY	6
	3.1	Participation	6
	3.2	Duration of Participation	6
SECTION	4	SEVERANCE BENEFITS	6
	4.1	Right to Severance Benefit	6
	4.2	Amount of Severance Benefit	6
SECTION	5	TERMINATION OF EMPLOYMENT	8
	5.1	Written Notice Required	8
	5.2	Termination Date	8
SECTION	6	ADDITIONAL PAYMENTS BY THE COMPANY	8
	6.1	Gross-Up Payment	8
	6.2	Determination By Accountant	9
	6.3	Notification Required	9
	6.4	Repayment	10
SECTION	7	SUCCESSORS TO COMPANY	11
	7.1	Successors and Sale of Operating Companies	11
		(a)       Successors	11
		(b)       Sale of Operating Companies	11

El Paso Energy Corporation	- i -	Table of Contents
Key Executive Severance Protection Plan

SECTION	8	AMENDMENT AND PLAN TERMINATION	11
	8.1	Amendment and Termination	11
	8.2	Form of Amendment	12
SECTION	9	MISCELLANEOUS	12
	9.1	Indemnification	12
	9.2	Employment Status	12
	9.3	Validity and Severability	12
	9.4	Governing Law; Choice of Forum	12
	9.5	Payment to Benefits Protection Trust	13

El Paso Energy Corporation
Key Executive Severance Protection Plan - ii - Table of Contents

EL PASO ENERGY CORPORATION

KEY EXECUTIVE SEVERANCE PROTECTION PLAN

AMENDED AND RESTATED EFFECTIVE AS OF AUGUST 1, 1998

     WHEREAS, the Board of Directors of El Paso Energy Corporation recognizes that the threat of an unsolicited takeover of the Company may occur which can result in significant distractions of its key executive personnel because of the uncertainties inherent in such a situation; and

     WHEREAS, the Board has determined that it is essential and in the best interest of the Company and its stockholders to retain the services of its key executive personnel in the event of a threat of a Change in Control of the Company and to ensure their continued dedication and efforts in such event without undue concern for their personal financial and employment security.

     NOW, THEREFORE, in order to fulfill the above purposes, the following plan has been developed and is hereby adopted.

SECTION 1 ESTABLISHMENT OF PLAN

     As of the Effective Date, the Company hereby establishes a severance compensation plan known as the El Paso Energy Corporation Key Executive Severance Protection Plan (the “Plan”) as set forth in this document.

SECTION 2 DEFINITIONS

     As used herein the following words and phrases shall have the following respective meanings unless the context clearly indicates otherwise.

2.1 BASE SALARY

     The amount a Participant is entitled to receive as wages or salary on an annualized basis, calculated immediately prior to a Change in Control.

2.2 BENEFITS PROTECTION TRUST

     The El Paso Energy Corporation Benefits Protection Trust.

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2.3 BOARD

     The Board of Directors of El Paso Energy Corporation.

2.4 BONUS AMOUNT

     The term “Bonus Amount” shall mean an amount equal to the Executive Employee’s maximum bonus which becomes payable to the Executive Employee in the event of a “change in control” under the Company’s 1995 Incentive Compensation Plan (or any other bonus plan or program then in effect) but excluding any single or one time “spot” award, for the fiscal year in which a Change in Control occurs had he or she continued in employment until the end of such fiscal year, assuming all performance targets and goals (if applicable) had been fully met by the Company and by the Executive Employee, as applicable, for such year.

2.5 CAUSE

     The Company may terminate the Executive Employee’s employment for “Cause.” A termination for Cause is a termination evidenced by a resolution adopted in good faith by two-thirds (2/3) of the Board that the Executive Employee (i) willfully and continually failed to substantially perform his or her duties with the Company (other than a failure resulting from the Executive Employee’s incapacity due to physical or mental illness) which failure continued for a period of at least thirty (30) days after a written notice of demand for substantial performance has been delivered to the Executive Employee specifying the manner in which the Executive Employee has failed to substantially perform, or (ii) willfully engaged in conduct which is demonstrably and materially injurious to the Company, monetarily or otherwise; provided, however, that no termination of the Executive Employee’s employment shall be for Cause as set forth in clause (ii) above until (A) there shall have been delivered to the Executive Employee a copy of a written notice setting forth that the Executive Employee was guilty of the conduct set forth in clause (ii) and specifying the particulars thereof in detail, and (B) the Executive Employee shall have been provided an opportunity to be heard by the Board (with the assistance of the Executive Employee’s counsel if the Executive Employee so desires). No act, nor failure to act, on the Executive Employee’s part shall be considered “willful” unless he or she has acted, or failed to act, with an absence of good faith and without a reasonable belief that his or her action or failure to act was in the best interest of the Company. Notwithstanding anything contained in this Plan to the contrary, no failure to perform by the Executive Employee after Notice of Termination is given by the Executive Employee shall constitute Cause.

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2.6 CHANGE IN CONTROL

     A “Change in Control” shall be deemed to occur:

          (a) if any person (as such term is used in Sections 13(d) and 14(d)(2) of the Exchange Act) is or becomes the “beneficial owner” (as defined in Rule 13d-3 of the Exchange Act), directly or indirectly, of securities of El Paso Energy Corporation representing twenty percent (20%) or more of the combined voting power of El Paso Energy Corporation’s then outstanding securities;

          (b) upon the first purchase of El Paso Energy Corporation’s Common Stock pursuant to a tender or exchange offer (other than a tender or exchange offer made by El Paso Energy Corporation);

          (c) upon the approval by El Paso Energy Corporation stockholders of a merger or consolidation, a sale or disposition of all or substantially all of El Paso Energy Corporation’s assets or a plan of liquidation or dissolution of El Paso Energy Corporation; or

          (d) if, during any period of two (2) consecutive years, individuals who at the beginning of such period constitute the Board of Directors of El Paso Energy Corporation cease for any reason to constitute at least a majority thereof, unless the election or nomination for the election by El Paso Energy Corporation’s stockholders of each new director was approved by a vote of at least two-thirds (2/3) of the directors then still in office who were directors at the beginning of the period.

Notwithstanding the foregoing, a Change in Control shall not be deemed to occur if El Paso Energy Corporation either merges or consolidates with or into another company or sells or disposes of all or substantially all of its assets to another company, if such merger, consolidation, sale or disposition is in connection with a corporate restructuring wherein the stockholders of El Paso Energy Corporation immediately before such merger, consolidation, sale or disposition own, directly or indirectly, immediately following such merger, consolidation, sale or disposition at least eighty percent (80%) of the combined voting power of all outstanding classes of securities of El Paso Energy Corporation resulting from such merger or consolidation, or to which El Paso Energy Corporation sells or disposes of its assets, in substantially the same proportion as their ownership in El Paso Energy Corporation immediately before such merger, consolidation, sale or disposition.

2.7 COMPANY

          El Paso Energy Corporation and the Operating Companies.

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2.8 EFFECTIVE DATE

     The date the Plan is approved by the Board, or such other date as the Board shall designate in its resolution approving the Plan, or any amendment or restatement thereof.

2.9 EXECUTIVE EMPLOYEE

     All employees of the Company employed in an Executive Salary Grade Position.

2.10 GOOD REASON

     “Good Reason” shall mean the occurrence of any of the following events or conditions:

          (a) a change in the Executive Employee’s status, title, position or responsibilities (including reporting responsibilities) which, in the Executive Employee’s reasonable judgment, represents a substantial reduction of the status, title, position or responsibilities as in effect immediately prior thereto; the assignment to the Executive Employee of any duties or responsibilities which, in the Executive Employee’s reasonable judgment, are inconsistent with such status, title, position or responsibilities; or any removal of the Executive Employee from or failure to reappoint or reelect him or her to any of such positions, except in connection with the termination of his or her employment for Cause, Permanent Disability, as a result of his or her death, or by the Executive Employee other than for Good Reason;

          (b) a reduction in the Executive Employee’s annual base salary;

          (c) the requirement by the Company that the Executive Employee (without the consent of the Executive Employee) to be based at any place outside a thirty-five (35) mile radius of his or her place of employment prior to a Change in Control, except for reasonably required travel on the Company’s business which is not materially greater than such travel requirements prior to the Change in Control;

          (d) the failure by the Company to (i) continue in effect any material compensation or benefit plan, program or practice in which the Executive Employee was participating at the time of the Change in Control, including, but not limited to, the Company’s 1995 Omnibus Compensation Plan, the Pension Plan, the Supplemental Benefits Plan, the 1995 Incentive Compensation Plan, the Deferred Compensation Plan, and the Retirement Savings Plan, with any amendments and restatements of such plans made prior to such Change in Control, or (ii) provide the Executive Employee with compensation and benefits at least equal (in terms of benefit levels and/or reward opportunities) to those provided for under each employee benefit plan, program and practice as in effect immediately prior to the Change in Control (or as in effect following the Change in Control, if greater);

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          (e) any material breach by the Company of any provision of this Plan; or

          (f) any purported termination of the Executive Employee’s employment for Cause by the Company which does not otherwise comply with the terms of this Plan as in effect at the time of a Change in Control.

2.11 NOTICE OF TERMINATION

     “Notice of Termination” shall mean a notice which indicates the specific provisions in this Plan relied upon as the basis for any termination of employment and shall set forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of the Executive Employee’s employment under the provision so indicated. No purported termination of employment shall be effective without such Notice of Termination.

2.12 OPERATING COMPANIES

     Subsidiary companies of the Company designated by the Company.

2.13 PARTICIPANT

     An Executive Employee who meets the eligibility requirements of Section 3.

2.14 PERMANENT DISABILITY

     A Participant shall be deemed to have become permanently disabled for purposes of this Plan if the Chief Executive Officer of the Company (or, in the case of a determination with respect to the Chief Executive Officer, the Board) finds, upon the basis of medical evidence satisfactory to him or her, that the Participant is totally disabled, whether due to physical or mental condition, so as to be prevented from engaging in further employment by the Company and that such disability will be permanent and continuous during the remainder of his or her life.

2.15 SEVERANCE BENEFIT

     The benefit payable in accordance with Section 4 of the Plan.

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SECTION 3 ELIGIBILITY

3.1 PARTICIPATION

     Each Executive Employee shall automatically be entitled to be a Participant in the Plan as of the Effective Date, or his or her date of hire by the Company, whichever occurs later.

3.2 DURATION OF PARTICIPATION

     A Participant shall cease to be a Participant in the Plan if he or she ceases to be an Executive Employee at any time prior to a Change in Control or, if his or her employment is terminated following a Change in Control under circumstances where he or she is not entitled to a Severance Benefit under the terms of this Plan. A Participant entitled to payment of a Severance Benefit shall remain a Participant in the Plan until the full amount of the Severance Benefit has been paid to him or her.

SECTION 4 SEVERANCE BENEFITS

4.1 RIGHT TO SEVERANCE BENEFIT

          (a) A Participant shall be entitled to receive from the Company a Severance Benefit in the amount provided in Section 4.2 if (i) a Change in Control has occurred and (ii) within two years thereafter, the Participant’s employment with the Company terminates for any reason, except that notwithstanding the provisions of this paragraph (a), no benefits under this Plan will be payable should the Participant’s termination of employment be (A) for Cause, (B) by reason of Permanent Disability, (C) voluntarily initiated by the Participant for other than Good Reason, or (D) by reason of the Participant’s death.

          (b) Notwithstanding any other provision of the Plan, the sale, divestiture or other disposition of an Operating Company (or part thereof), shall not be deemed to be a termination of employment of employees employed by such Operating Company, and such employees shall not be entitled to benefits from the Company under this Plan as a result of such sale, divestiture, or other disposition, or as a result of any subsequent termination of employment, provided the provisions of Section 7.1(b) have been satisfied.

4.2 AMOUNT OF SEVERANCE BENEFIT

     If a Participant’s employment is terminated in circumstances entitling him or her to a Severance Benefit as provided in Section 4.1, such Participant shall be entitled to the following benefits:

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          (a) the Company shall pay to the Participant, as severance pay and in lieu of any further salary for periods subsequent to the Termination Date (as specified in Section 5.2), in a single payment (without any discount for accelerated payment), an amount in cash equal to three (3) times the sum of (A) the Participant’s Base Salary and (B) the Bonus Amount;

          (b) for a period of eighteen (18) months subsequent to the Participant’s termination of employment, the Company shall at its expense continue on behalf of the Participant and his or her dependents and beneficiaries, the basic life insurance, flexible spending account, medical and dental benefits which were being provided to the Participant at the time of termination of employment. The benefits provided in this Subsection 4.2(b) shall be no less favorable to the Participant, in terms of amounts and deductibles and costs to him or her, than the coverage provided the Participant under the plans providing such benefits at the time Notice of Termination is given. The Company’s obligation hereunder to provide the foregoing benefits shall terminate if the Participant obtains health benefits coverage under a subsequent employer’s benefit plans. The Company also shall pay a lump sum equal to the amount of any additional income tax payable by the Participant and attributable to the benefits provided under this subparagraph (b) at the time such tax is imposed upon the Participant;

          (c) the Company shall pay a lump sum pension supplement payable under the terms of the El Paso Energy Corporation Supplemental Benefit Plan (“Supplemental Plan”) equal to a pension calculated by adding three years of additional credited pension service to the Participant’s existing credited pension service as of the termination of the Participant’s employment, and then by calculating the Participant’s pension in accordance with the formula provided in the pension plan. A Participant who is entitled to a pension supplement under any other agreement between such Participant and the Company may elect, in writing, to receive the pension supplement provided under this subparagraph (c) in lieu of, but not in addition to, such other pension supplement as may be provided by such other agreement. In the event that no election is made, the Participant shall forego his or her right to receive the pension supplement provided under this subparagraph;

          (d) the Company shall transfer to the Participant, all right, title or other ownership interest it may have in any automobile, if any, then being provided by the Company for use by the Participant;

          (e) the Company shall transfer to the Participant, any right, title or ownership in any club memberships provided by the Company;

     The amounts provided for in Section 4.2(a), (c), (d) and (e) shall be paid or transferred within thirty (30) days after the Executive Employee’s termination of employment. The Participant shall not be required to mitigate the amount of any

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payment provided for in this Plan by seeking other employment or otherwise and no such payment shall be offset or reduced by the amount of any compensation or benefits provided to the Executive Employee in any subsequent employment.

SECTION 5 TERMINATION OF EMPLOYMENT

5.1 WRITTEN NOTICE REQUIRED

     Any purported termination of employment, either by the Company or by the Participant, shall be communicated by written Notice of Termination to the other.

5.2 TERMINATION DATE

     In the case of the Participant’s death, the Participant’s Termination Date shall be his her date of death. In all other cases, the Participant’s Termination Date shall be the date specified in the Notice of Termination subject to the following:

          (a) If the Participant’s employment is terminated by the Company for Cause or due to Permanent Disability, the date specified in the Notice of Termination shall be at least thirty (30) days from the date the Notice of Termination is given to the Participant, provided that in the case of Permanent Disability the Participant shall not have returned to the full-time performance of his or her duties during such period of at least thirty (30) days; and

          (b) If the Participant terminates his or her employment for Good Reason, the date specified in the Notice of Termination shall not be more than sixty (60) days from the date the Notice of Termination is given to the Company.

SECTION 6 ADDITIONAL PAYMENTS BY THE COMPANY

6.1 GROSS-UP PAYMENT

     In the event it shall be determined that any payment or distribution of any type by the Company to or for the benefit of the Participant, whether paid or payable or distributed or distributable pursuant to the terms of this Plan or otherwise (the “Total Payments”), would be subject to the excise tax imposed by Section 4999 of the Internal Revenue Code of 1986, as amended (the “Code”) or any interest or penalties with respect to such excise tax (such excise tax, together with any such interest and penalties, are collectively referred to as the “Excise Tax”), then the Participant shall be entitled to receive an additional payment (a “Gross-Up Payment”) in an amount such that after payment by the Participant of all taxes (including any interest or penalties imposed with respect to such taxes), including any Excise Tax, imposed upon the Gross-Up Payment, the Participant retains an amount of the Gross-Up Payment equal to the Excise Tax imposed upon the Total Payments. Payment of the Gross-Up Payment shall be made in accordance with Section 6.3.

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6.2 DETERMINATION BY ACCOUNTANT

     All determinations required to be made under this Section 6, including whether a Gross-Up Payment is required and the amount of such Gross-Up Payment, shall be made by the independent accounting firm retained by the Company on the date of Change in Control (the “Accounting Firm”), which shall provide detailed supporting calculations both to the Company and the Participant within 15 business days of the date of termination, if applicable, or such earlier time as is requested by the Company. If the Accounting Firm determines that no Excise Tax is payable by the Participant, it shall furnish the Participant with an opinion that he or she has substantial authority not to report any Excise Tax on his or her federal income tax return. Any determination by the Accounting Firm shall be binding upon the Company and the Participant. As a result of the uncertainty in the application of Section 4999 of the Code at the time of the initial determination by the Accounting Firm hereunder, it is possible that Gross-Up payments which will not have been made by the Company should have been made (“Underpayment”), consistent with the calculations required to be made hereunder. In the event that the Company exhausts its remedies pursuant to Section 6.3 and the Participant thereafter is required to make a payment of any Excise Tax, the Accounting Firm shall determine the amount of the Underpayment that has occurred and any such Underpayment shall be promptly paid by the Company to or for the benefit of the Participant.

6.3 NOTIFICATION REQUIRED

     The Participant shall notify the Company in writing of any claim by the Internal Revenue Service that, if successful, would require the payment by the Company of the Gross-Up Payment. Such notification shall be given as soon as practicable but no later than ten (10) business days after the Participant knows of such claim and shall apprise the Company of the nature of such claim and the date on which such claim is requested to be paid. The Participant shall not pay such claim prior to the expiration of the thirty (30) day period following the date on which it gives such notice to the Company (or such shorter period ending on the date that any payment of taxes with respect to such claim is due). If the Company notifies the Participant in writing prior to the expiration of such period that it desires to contest such claim, the Participant shall:

          (a) give the Company any information reasonably requested by the Company relating to such claim,

          (b) take such action in connection with contesting such claim as the Company shall reasonably request in writing from time to time, including, without limitation, accepting legal representation with respect to such claim by an attorney reasonably selected by the Company,

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          (c) cooperate with the Company in good faith in order to effectively contest such claim,

          (d) permit the Company to participate in any proceedings relating to such claim, provided, however, that the Company shall bear and pay directly all costs and expenses (including additional interest and penalties) incurred in connection with such contest and shall indemnify and hold the Participant harmless, on an after-tax basis, for any Excise Tax or income tax, including interest and penalties with respect thereto, imposed as a result of such representation and payment of costs and expenses. Without limitation on the foregoing provisions of this Section 6.3, the Company shall control all proceedings taken in connection with such contest and, at its sole option, may pursue or forgo any and all administrative appeals, proceedings, hearings and conferences with the taxing authority in respect of such claim and may, at its sole option, either direct the Participant to pay the tax claimed and sue for a refund, or contest the claim in any permissible manner, and the Participant agrees to prosecute such contest to a determination before any administrative tribunal, in a court of initial jurisdiction and in one or more appellate courts, as the Company shall determine; provided, however, that if the Company directs the Participant to pay such claim and sue for a refund, the Company shall advance the amount of such payment to the Participant, on an interest-free basis and shall indemnify and hold the Participant harmless, on an after-tax basis, from any Excise Tax or income tax, including interest or penalties with respect thereto, imposed with respect to such advance or with respect to any imputed income with respect to such advance; and further provided that any extension of the statute of limitations relating to payment of taxes for the taxable year of the Participant with respect to which such contested amount is claimed to be due is limited solely to such contested amount. Furthermore, the Company’s control of the contest shall be limited to issues with respect to which a Gross-Up Payment would be payable hereunder and the Participant shall be entitled to settle or contest, as the case may be, any other issue raised by the Internal Revenue Service or any other taxing authority.

6.4 REPAYMENT

     If, after the receipt by the Participant of an amount advanced by the Company pursuant to Section 6.3, the Participant becomes entitled to receive any refund with respect to such claim, the Participant shall (subject to the Company’s complying with the requirements of Section 6.3) promptly pay to the Company the amount of such refund (together with any interest paid or credited thereon after taxes applicable thereto). If, after the receipt by the Participant of an amount advanced by the Company pursuant to Section 6.3, a determination is made that the Participant shall not be entitled to any refund with respect to such claim and the Company does not notify the Participant in writing of its intent to contest such denial of refund prior to the expiration of thirty (30)

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days after such determination, then such advance shall be forgiven and shall not be required to be repaid and the amount of such advance shall offset, to the extent thereof the amount of Gross-Up Payment required to be paid.

SECTION 7 SUCCESSORS TO COMPANY

7.1 SUCCESSORS AND SALE OF OPERATING COMPANIES

  (a)  Successors

This Plan shall bind any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Company, in the same manner and to the same extent that the Company would be obligated under this Plan if no succession had taken place. In the case of any transaction in which a successor would not by the foregoing provision or by operation of law be bound by this Plan, the Company shall require such successor expressly and unconditionally to assume and agree to perform the Company’s obligations under this Plan, in the same manner and to the same extent that the Company would be required to perform if no such succession had taken place.

(b) Sale of Operating Companies

In the event that one or more Operating Companies (or part thereof) are sold, divested, or otherwise disposed of by the Company subsequent to a Change in Control, the Company shall require such purchaser or acquirer, as a condition precedent to such purchase or acquisition, to assume, and agree to perform the Company’s obligations under the Plan, in the same manner, and to the same extent that the Company would be required to perform if no such acquisition or purchase had taken place. In such circumstances, the purchaser or acquirer shall be solely responsible for providing any benefits payable under this Plan to such employees.

SECTION 8 AMENDMENT AND PLAN TERMINATION

8.1 AMENDMENT AND TERMINATION

          This Plan may be terminated or amended in any respect by resolution adopted by two-thirds (2/3) of the Board, provided, however, that no such amendment or termination of the Plan may be made if such amendment or termination would adversely affect any right of an Executive Employee who became a Participant prior to the later of (a) the date of adoption of any such amendment or termination, or (b) the effective date of any such amendment or termination, and provided further, that the Plan no longer shall be subject

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to amendment, change, substitution, deletion, revocation or termination in any respect whatsoever following a Change in Control. The Board of Directors amended and restated the Plan effective as of August 1, 1998, in connection with the reorganization of the Company into a holding company structure whereby El Paso Energy Corporation became the publicly held company and El Paso Natural Gas Company became a wholly owned subsidiary. This Plan was assumed by El Paso Energy Corporation pursuant to an Assignment and Assumption Agreement effective as of August 1, 1998, by and between El Paso Energy Corporation and El Paso Natural Gas Company.

8.2 FORM OF AMENDMENT

     The form of any amendment or termination of the Plan shall be a written instrument signed by a duly authorized officer or officers of the Company, certifying that the amendment or termination has been approved by the Board.

SECTION 9 MISCELLANEOUS

9.1 INDEMNIFICATION

     If, after a Change in Control, a Participant institutes any legal action in seeking to obtain or enforce, or is required to defend in any legal action the validity or enforceability of, any right or benefit provided by this Plan, the Company will pay for all actual legal fees and expenses as they are incurred by such Participant.

9.2 EMPLOYMENT STATUS

     This Plan does not constitute a contract of employment or impose on the Company any obligation to retain the Participant as an Employee, to change the status of the Participant’s employment as an Executive Employee, or to change any employment policies of the Company.

9.3 VALIDITY AND SEVERABILITY

     The invalidity or unenforceability of any provision of the Plan shall not affect the validity or enforceability of any other provision of the Plan, which shall remain in full force and effect, and any prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

9.4 GOVERNING LAW; CHOICE OF FORUM

     The validity, interpretation, construction and performance of the Plan shall in all respects be governed by the laws of the State of Texas. A Participant shall be entitled to enforce the provisions of this Plan in any state or federal court located in the State of Texas, in addition to any other appropriate forum.

9.5 PAYMENT TO BENEFITS PROTECTION TRUST

     Notwithstanding any other provision of the Plan, the Company shall not be required to make any payment to a Participant under the terms of this Plan if such payment is otherwise made to the Participant by the Benefits Protection Trust in accordance with the provisions of said Benefits Protection Trust.

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     IN WITNESS WHEREOF, the Company has caused the Plan to be amended and restated effective as of August 1, 1998.

		EL PASO ENERGY CORPORATION
		By	/s/ Joel Richards III
		Title: Executive Vice President
ATTEST:
By	/s/ David L. Siddall
Title: Corporate Secretary

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EX-10.P

EXHIBIT 10.P

EL PASO ENERGY CORPORATION

DIRECTOR CHARITABLE AWARD PLAN

AMENDED AND RESTATED EFFECTIVE AS OF AUGUST 1, 1998

TABLE OF CONTENTS

SECTION 1 ESTABLISHMENT, PURPOSE, AND DURATION	1
1.1 Establishment of the Plan	1
1.2 Purpose of the Plan	1
1.3 Duration of the Plan	1
SECTION 2 DEFINITIONS AND CONSTRUCTION	1
SECTION 3 ADMINISTRATION	3
3.1 Management Committee	3
3.2 Decisions Binding	4
SECTION 4 ELIGIBILITY AND PARTICIPATION	4
4.1 Eligibility	4
4.2 Actual Participation	4
SECTION 5 CHARITABLE AWARDS	4
5.1 Size of Charitable Awards	4
5.2 Designation of Donees	4
5.3 Changes in Designations of Donees	5
5.4 Security for Donations	5
5.5 Change in Control	5
5.6 Payment of Charitable Awards	6
SECTION 6 AMENDMENT, MODIFICATION, AND TERMINATION	6
SECTION 7 INDEMNIFICATION	6
SECTION 8 MISCELLANEOUS	7
8.1 Successors	7
8.2 Nontransferability	7
8.3 Gender and Number	7
8.4 Severability	7
8.5 Governing Law	7

El Paso Energy Corporation
Director Charitable Award Plan -i- Table of Contents

EL PASO ENERGY CORPORATION
DIRECTOR CHARITABLE AWARD PLAN
AMENDED AND RESTATED EFFECTIVE AS OF AUGUST 1, 1998

SECTION 1 ESTABLISHMENT, PURPOSE, AND DURATION

1.1 ESTABLISHMENT OF THE PLAN

     El Paso Energy Corporation, a Delaware corporation (hereinafter referred to as the “Company”), hereby establishes a charitable award program for Directors (as defined below), to be known as the “El Paso Energy Corporation Director Charitable Award Plan” (hereinafter referred to as the “Plan”), as set forth in this document. The Plan provides for the contribution by the Company of one million dollars ($1,000,000) on behalf of each Director, to Charitable Organizations (as defined below)of each Director’s choice subject to the terms and provisions of this Plan.

     The Board of Directors of the Company amended and restated effective as of August 1, 1998. The term “Effective Date” shall mean January 15, 1992.

1.2 PURPOSE OF THE PLAN

     The purpose of the Plan is to promote the mutual interest of the Directors and the Company to support worthy Charitable Organizations, and to enhance the positive image of the Company.

     The Plan is further intended to acknowledge the service of the Company’s Directors, and to aid the Company in its ability to attract, motivate, and retain the services of highly qualified Directors, upon whose judgment, interest, and special effort the continued successful operation of the Company largely is dependent.

1.3 DURATION OF THE PLAN

     The Plan commenced on the Effective Date and shall remain in effect until terminated by the Board of Directors.

SECTION 2 DEFINITIONS AND CONSTRUCTION

     Whenever used in this Plan, the following terms shall have the meanings set forth below and, when the meaning is intended, the initial letter of the word is capitalized.

     (a) “Board” or “Board of Directors” means the Board of Directors of the Company.

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     (b) “Change in Control” of the Company shall be deemed to have occurred if the conditions set forth in any one or more of the following paragraphs shall have been satisfied:

     (i) any person (as such term is used in Sections 13(d) and 14(d)(2) of the Exchange Act) being or becoming the “beneficial owner” (as defined in Rule 13d-3 of the Exchange Act) directly or indirectly, of securities of the Company representing twenty percent (20%) or more of the combined voting power of the then outstanding securities of the Company,

     (ii) the first purchase of the Company’s Common Stock pursuant to a tender or exchange offer (other than a tender or exchange offer made by the Company),

     (iii) the approval by the Company’s stockholders of a merger or consolidation, a sale or disposition of all or substantially all of the Company’s assets or a plan of liquidation or dissolution of the Company, or

     (iv) during any period of two (2) consecutive years, individuals who at the beginning of such period constitute the Board of Directors of the Company ceasing for any reason to constitute at least a majority thereof, unless the election or nomination for the election by the Company’s stockholders of each new director was approved by a vote of at least two-thirds of the directors then still in office who were directors at the beginning of the period.

Notwithstanding the foregoing, a Change in Control shall not be deemed to occur if the Company either merges or consolidates with or into another company or sells or disposes of all or substantially all of its assets to another company, if such merger, consolidation, sale or disposition is in connection with a corporate restructuring wherein the stockholders of the Company immediately before such merger, consolidation, sale or disposition own, directly or indirectly, immediately following such merger, consolidation, sale or disposition at least eighty percent (80%) of the combined voting power of all outstanding classes of securities of the company resulting from such merger or consolidation, or to which the Company sells or disposes of its assets, in substantially the same proportion as their ownership in the Company immediately before such merger, consolidation, sale or disposition.

     (c) “Charitable Award” means, individually or collectively, a donation to be made to a Charitable Organization chosen by a Participant pursuant to the terms of Section 5 herein.

     (d) “Charitable Organization” means any public or private charitable organization in the United States or its possessions which is a corporation, trust,

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Director Charitable Award Plan Page 2

community chest, fund, foundation, or association, provided contributions to such entity are deductible under Section 170(c) of the Code.

     (e) “Code” means the Internal Revenue Code of 1986, as amended, or any successor statute, and the Treasury Regulations promulgated thereunder.

     (f) “Committee” means the management committee as specified in Section 3 herein.

     (g) “Company” means El Paso Energy Corporation, a Delaware corporation, or any successor thereto as provided in Section 8.1 herein.

     (h) “Director” means any individual who is a member of the Board of Directors of the Company.

     (i) “Effective Date” means the date on which the Plan became effective, as designated by the Board of Directors pursuant to Section 1.1 herein.

     (j) “Exchange Act” means the Securities Exchange Act of 1934, as amended from time to time, or any successor Act thereto.

     (k) “Participant” means a Director of the Company who has been notified of his or her eligibility to participate in this Plan, pursuant to Section 4.2 herein.

     (l) “Person” shall have the meaning ascribed to such term in Section 3(a)(9) of the Exchange Act, and used in Sections 13(d) and 14(d) thereof, including a “group” as defined in Section 13(d).

     (m) “Qualified Donee” means any Charitable Organization which has not been denied status as a Qualified Donee by the Board of Directors, pursuant to Section 5.2 herein.

SECTION 3 ADMINISTRATION

3.1 MANAGEMENT COMMITTEE

     The Plan shall be administered by the Board of Directors and a management committee (the “Committee”) consisting of the Chief Executive Officer and such other senior officers as he or she shall designate. The Committee shall interpret the Plan, prescribe, amend, and rescind rules relating to it, select eligible Participants, and take all other actions necessary for its administration. No member of the Committee shall vote on any matter that pertains solely to himself or herself.

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3.2 DECISIONS BINDING

     All determinations and decisions made by the Board of Directors and/or the Committee pursuant to the administration of this Plan shall be final, conclusive, and binding on all parties, including the Company, its stockholders, employees, Participants, and their estates and beneficiaries.

SECTION 4 ELIGIBILITY AND PARTICIPATION

4.1 ELIGIBILITY

     Persons who are elected to serve on the Board of Directors on or after the Effective Date shall be eligible to participate in this Plan on the second anniversary of the date of their election to the Board; provided, however, that such Directors must have continuously served on the Board throughout such two-year period.

4.2 ACTUAL PARTICIPATION

     Subject to the terms and conditions of this Plan, the Committee shall notify each eligible Director of his or her eligibility to participate in this Plan as soon as practicable following the date that each such Director first becomes eligible for participation.

SECTION 5 CHARITABLE AWARDS

5.1 SIZE OF CHARITABLE AWARDS

     Each Participant shall have the right to designate Qualified Donees to which an aggregate of up to one million dollars ($1,000,000) shall be donated by the Company on behalf of the Participant. Participants may designate up to four Qualified Donees; provided, however, that the total funds which shall be donated by the Company on behalf of any one Participant shall not exceed one million dollars ($1,000,000).

5.2 DESIGNATION OF DONEES

     Each Participant shall nominate Charitable Organizations to receive Charitable Awards by providing formal notice of such nominations to the Committee. Following the receipt of the nominations of organizations, the Committee will approve the nomination or recommend to the Board that the nomination be denied. In the event the Committee does not recommend to the Board that the nomination be denied within six months of receipt of such nomination, the nomination shall be deemed accepted by the Committee. Further, if the Participant should die before the Committee, or the Board in the case of denials, acts on the nominations, such nomination shall be deemed accepted provided the nominee is a qualified Charitable Organization, as defined herein. The Board of

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Directors, by majority vote, shall have the authority to deny status as a Qualified Donee to any organization nominated by a Participant. In the event one or more organizations nominated by a Participant for status as a Qualified Donee are denied such status by the Board of Directors, the Participant may nominate additional organizations to receive a Charitable Award, subject to the approval of the Committee (or the denial by the Board, as applicable). If a Participant fails to designate a Qualified Donee, the Charitable Award to be made on behalf of such Participant shall lapse.

     All nominations of organizations to receive Charitable Awards shall be made on a Charitable Award Nomination Form, which shall specify the following: (i) the name of the nominated organization; (ii) the amount desired by the Participant to be donated to the organization; (iii) the name under which the donation is to be made; and (iv) any other terms and provisions deemed necessary by the Board of Directors or the Committee. Each completed Charitable Award Nomination Form shall be submitted to the Executive Vice President, Human Resources and Administration.

5.3 CHANGES IN DESIGNATIONS OF DONEES

     Participants may, at any time, nominate an alternative Charitable Organization to receive a Charitable Award (subject to Committee approval, as described in Section 5.2 herein). In addition, Participants may, at any time, request a change in the amount of money to be donated to each such Qualified Donee, or a change in the name under which the donation is to be made, subject to approval (as described in Section 5.2 herein).

     Changes in the designation of Qualified Donees or in any other terms applicable to the Charitable Awards, shall be made on a Charitable Award Nomination Form, which shall specify the new or additional organizations nominated to receive a Charitable Award, the amount of money to be donated in the name of the Participant to each Qualified Donee, and any other terms or provisions deemed necessary by the Board of Directors or the Committee.

5.4 SECURITY FOR DONATIONS

     The Company’s obligations under this Plan may be unfunded and unsecured promises to donate money in the future. No Qualified Donee shall have the right to a donation solely by virtue of the designation of such Qualified Donee by a Participant. Following the death of a Participant, the rights of each Qualified Donee designated by the Participant shall be those of a general unsecured creditor of the Company.

5.5 CHANGE IN CONTROL

     Notwithstanding any other provision of this Plan, upon a Change in Control of the Company, the commitment of the Company to donate the Charitable Awards to the Qualified Donees shall become an irrevocable obligation. Following a Change in Control, the Board of Directors may not amend, modify, or terminate the Charitable

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Awards of the Participants in a way which would decrease the value of the donations. In addition, following a Change in Control, the Participants shall retain the right to change the designations of their Qualified Donees, pursuant to Section 5.3 herein, without Board or Committee review.

5.6 PAYMENT OF CHARITABLE AWARDS

     As soon as practicable following the death of a Participant, the Company shall donate the Charitable Awards to the Qualified Donees, in the amounts requested by the Participant and approved by the Board of Directors or Committee. Such payment shall be made in one lump sum. No contribution will be made under this Plan to an otherwise Qualified Donee if the payment thereof will result in the receipt of property or other direct economic benefits to the Company or its subsidiaries or to the Participants or to the family members of any Participant.

SECTION 6 AMENDMENT, MODIFICATION, AND TERMINATION

     Except as set forth in Section 5.5, the Board may from time to time amend, suspend, or terminate the Plan, in whole or in part, and if the Plan is suspended or terminated, the Board may reinstate any or all of its provisions. The Committee may amend the Plan provided that it may not suspend or terminate the Plan or substantially increase the administrative cost of the Plan or the obligations of the Company. The Board of Directors amended and restated the Plan effective as of August 1, 1998, in connection with the reorganization of the Company into a holding company structure whereby El Paso Energy Corporation became the publicly held company and El Paso Natural Gas Company became a wholly owned subsidiary. This Plan was assumed by El Paso Energy Corporation pursuant to an Assignment and Assumption Agreement effective as of August 1, 1998, by and between El Paso Energy Corporation and El Paso Natural Gas Company.

SECTION 7 INDEMNIFICATION

     Each individual who is or shall have been a member of the Committee, or of the Board, shall be indemnified and held harmless by the Company against and from any loss, cost, liability, or expense that may be imposed upon or reasonably incurred by him or her in connection with or resulting from any claim, action, suit, or proceeding to which he or she may be a party or in which he or she may be involved by reason of any action taken or failure to act under this Plan and against and from any and all amounts paid by him or her in settlement thereof, with the Company’s approval, or paid by him or her in satisfaction of any judgment in any such action, suit, or proceeding against him or her, provided he or she shall give the Company an opportunity, at its own expense, to handle and defend the same before he or she undertakes to handle and defend it on his or her own behalf.

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     The foregoing right in indemnification shall not be exclusive of any other rights of indemnification to which such individuals may be entitled under the Company’s Restated Certificate of Incorporation or By-laws, as a matter of law, or otherwise, or any power that the Company may have to indemnify them or hold them harmless.

SECTION 8 MISCELLANEOUS

8.1 SUCCESSORS

     All obligations of the Company under this Plan shall be binding on any successor to the Company, whether the existence of such successor is the result of a direct or indirect purchase, merger, consolidation, or otherwise, of all or substantially all of the business and/or assets of the Company.

8.2 NONTRANSFERABILITY

     The right to nominate organizations to receive Charitable Awards under this Plan shall be personal to Participants, and may not be sold, transferred, pledged, assigned, or otherwise alienated or hypothecated.

8.3 GENDER AND NUMBER

     Except where otherwise indicated by the context, any masculine term used herein also shall include the feminine; the plural shall include the singular, and the singular shall include the plural.

8.4 SEVERABILITY

     In the event any provision of this Plan shall be held illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining parts of this Plan, and this Plan shall be construed and enforced as if the illegal or invalid provision had not been included.

8.5 GOVERNING LAW

     To the extent not preempted by Federal law, this Plan, and all agreements hereunder, shall be construed in accordance with and governed by the laws of the State of Texas.

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     IN WITNESS WHEREOF, the Company has caused the Plan to be amended and restated effective as of August 1, 1998.

		EL PASO ENERGY CORPORATION
		By	/s/ Joel Richards III
		Title: Executive Vice President
ATTEST:
By	/s/ David L. Siddall
Title: Corporate Secretary

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EX-10.R

EXHIBIT 10.R

[EL PASO ENERGY LOGO]

POLICY SUBJECT:  RELOCATION FOR EMPLOYEES RELOCATING FROM
EL PASO, TEXAS TO HOUSTON, TEXAS, AS A RESULT
OF RELOCATING THE CORPORATE OFFICE

EFFECTIVE: NOVEMBER 1, 1996

I.   POLICY

When a regular full-time employee is requested to transfer to Houston, Texas, in 1996 or within the first six months of 1997, as a result of the relocation of El Paso Energy Corporation’s headquarters from El Paso, Texas, to Houston, the employee will be reimbursed for certain relocation expenses. The employee is to exercise prudence in any relocation transaction to ensure that reimbursable costs are minimized.

The company has contracted with Prudential Relocation to provide relocation assistance for employees.

II.   GENERAL PROVISIONS

•   Transfer must be made at request of the company.

•   A Transfer must meet IRS regulations specifying that the move must be over 50 miles and employee must work full time in the general area of the new work location for at least 39 weeks during the 12 months immediately following the move.

•   One set of benefits per household.

•   Covers employee and all persons residing permanently in employee’s household when transfer request is made.

III.   GENERAL PROVISIONS

A.   LUMP SUM PAYMENTS

1.   INCIDENTAL ALLOWANCE

The company will provide an incidental allowance equal to 10 percent of his or her annual post-move base salary, grossed up for taxes. The incidental allowance is to be used for expenses not covered elsewhere in this policy. Examples of items which are considered incidental expenses include, but are not limited to, deposits for utilities, deposits for renting and leasing, movement of possessions not covered by this policy (Item III, Section B), cleaning/painting/repairs of new residence, dependent care, equity in new

residence, upgrade of fixtures and appliances, landscaping, movement of a mobile home that is not the primary residence, babysitting and boarding of pets necessitated by the relocation, drivers license, automobile registration, forfeited membership fees, housecleaning and any expenses related to establishing a residence at the new location not covered by the homefinding allowance. Prudential will issue this payment.

2.

HOMEFINDING ALLOWANCE The company will provide a lump sum payment, grossed up for taxes, for the purpose of establishing a residence at the new location. The payment is based on one-half of the cost of an 8-day, 7-night trip for the employee and one household member to the new location, including round-trip coach airfare, accommodations at a moderately priced hotel, car rental and meals. Prudential will issue this payment.

3.

TEMPORARY LIVING ALLOWANCE The company will provide a lump sum payment, grossed up for taxes, equal to 3 percent of their annual post-move base salary (a minimum of $1,500) for temporary living expenses for the employee. The Prudential counselor can help make temporary housing arrangements. The employee should call the Prudential counselor and discuss temporary living requirements.

B.   MOVEMENT OF HOUSEHOLD GOODS AND STORAGE

Prudential Relocation will arrange for packing, transporting, and unpacking of furniture and normal household effects and the costs will be paid directly by the company. The Prudential counselor will work directly with the employee to arrange for the movement of household effects. Prudential can make arrangements to ship up to two cars.

The following and similar items will not be moved at the company’s expense:

•   recreational motor vehicles

•   boats, tractors (too large for regular shipment along with household goods)

•   more than two vehicles, i.e., personal automobiles and motorcycles

•   patio slate, rocks, shrubbery, firewood, etc.

•   lumber or other building material such as cement, gravel, sand, bricks, etc.

•   frozen food

•   pets

•   plants

Coverage through Prudential includes the purchase of full replacement cost insurance of up to $150,000. The employee is responsible for declaring the actual value of the household goods for the full replacement coverage. Full

Page 2

	replacement cost coverage for any declaration of actual value which exceeds $150,000 must have special approval by the Executive Vice President, Human Resources and Administration. Charges for full replacement cost coverage will be paid by the company. In the event of damage to any property, the Prudential counselor will assist in processing insurance claims to facilitate timely resolution of disputes.
	Prudential will arrange for the storage of household goods for a period of 60 days if it is not feasible to immediately move them into a newly acquired residence at the new location. Only those items on the original bill of lading will be stored at company expense. The storage expenses will be paid directly by the company.
	In lieu of company arranged movement of household goods, an employee is eligible for a lump sum payment of $750, not grossed up for taxes, to move his/her household goods. The employee will be responsible for obtaining insurance associated with the move.
	The expense of moving a mobile home, when it is in moveable condition and if the employee does not own the land on which it is situated, is covered if it is the primary residence. Movement of household goods will also be covered, but only when such items cannot be moved within the mobile home. Normal covered costs include tow truck charges, removal and reinstallation of fences, skirting and porches, utilities connection, lease penalty up to three months, insurance and applicable state and local fees to transport and reinstallation of safety devices. If the employee owns the land, the company will not cover the cost of moving the mobile home. It will be covered under the provisions of the home sale program in Section III, paragraph D2.
C.	TRAVEL TO NEW LOCATION The company will reimburse the costs associated with moving the employee and all permanent members of the household to the new location. The following expenses will be reimbursed or arranged:

•   If the employee elects to drive to the new location, mileage at current IRS rate for up to two cars;

•   Cost of one-way coach airfare for employee and all persons residing permanently in the household;

•   Moderate hotel lodging, not to exceed two nights, and reasonable meals not to exceed $25 per person per day for three days.

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D.   HOME SALE PROGRAM

An employee who owns his/her primary residence is eligible for home sale benefits offered by Prudential Relocation. The employee must contact his/her Prudential counselor to ensure the maximum benefits are obtained.

1.   INELIGIBLE PROPERTIES — The following properties are considered ineligible properties and therefore will not be eligible for reimbursement of costs associated with sale or purchase of such properties:

•   Farms, ranches, orchards, summer homes, duplexes or any multiple unit properties

•   Cooperative apartments

•   Any property with excess acreage for the area

•   Any property with over 5 acres

•   Any residence that contains hazardous or toxic substances or is near hazardous or toxic substances

•   Non-residential use property, either partial or whole use

•   Any property with no access/no easement

•   Properties without marketable title (i.e., landlocked properties and properties with a cloud on the title)

•   Any properties that have repairs that are more than 10 percent of the appraised value

•   Mobile homes — see Item III, Section D #2

	All properties must be in marketable condition with no major repairs, structural or code problems which have not been repaired or deducted from equity.
2.	MOBILE HOMES — In lieu of purchasing mobile homes, the company will make a lump sum payment to the employee, grossed up for taxes, if the mobile home meets the following criteria:

•   it is the primary residence

•   it is permanently affixed

•   it meets state requirements

•   it is on property (land) owned by the employee

The lump sum will be based on the average of one appraisal and one broker’s price opinion (must be within 5 percent of each other) times 8 percent.

Mobile homes of a moveable nature and reasonable distance are addressed in this policy under Item III, Section B. If the mobile home is moved, the employee is not eligible for a lump sum payment.

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3.	GUARANTEED OFFER AND HOME MARKETING ASSISTANCE — Employees are encouraged to list their home with a qualified broker and to actively participate in the marketing of the home. The Prudential counselor can assist the employee in the selection of a qualified broker to help maximize marketing efforts. It is recommended that an employee speak to the Prudential counselor before signing any documents with realtors/agents. Any commission that is not considered normal for the area will not be reimbursed by the company.
	The employee must market their home for at least 60 days and the list price cannot be more than 110 percent of the appraised price in order to be eligible for the Loss Protection on Sale of Home and the Home Sale Program. When listing a home, the employee must include the following exclusion clause to be eligible for the guaranteed offer and/or the amended sale benefits:
	“It is understood and agreed that regardless of whether or not an offer is presented by a ready, willing, and able buyer:

1.	No commission or compensation shall be earned by, or due and payable to broker until the sale of the property has been consummated between seller and buyer, the deed delivered to the buyer, and the purchase price delivered to the seller; and
2.	The seller reserves the right to sell the property at any time to Prudential Relocation, a Division of Prudential Residential Services, Limited Partnership or                    [Name of any other party to be covered by this exclusion clause] (individually and collectively a “Named Prospective Purchaser”) to either pay a commission or to continue this listing.”

While marketing the home, the Prudential counselor will work with the employee to establish a guaranteed offer which is based on the appraisal process. The employee will be able to choose an appraiser and a broker from a list of independent appraisers and brokers provided by the Prudential counselor and approved by the company. To the extent the lower value is within 5 percent of the higher, the two values will be averaged to determine the guaranteed offer. If the two values are not within a 5 percent spread, the employee will be asked to choose a second appraiser from the approved list. The two highest values will then be averaged to determine the guaranteed offer. The employee will have 90 days from the day Prudential makes the guaranteed offer to accept it.

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4.

AMENDED VALUE — If an acceptable offer is received, the employee should contact the Prudential counselor immediately. The employee should not orally accept an offer, deposit, or sign any agreement until speaking with the Prudential counselor. If the employee presents an offer which is 97 percent of the Prudential guaranteed offer, the company will ensure the guaranteed offer will be realized. If an employee receives a bona fide offer for more than the guaranteed offer, the guaranteed offer will be amended to the higher offer.

5.

HOME SALE BONUS — As an incentive to the transferring employee, the company will pay a bonus based on 3 percent of the sale price of the home. The bonus will not be grossed up for taxes and will be:

•   based on the sale price of the home

•   paid if the sale is at least 97 percent of the guaranteed offer

•   a minimum of $2,000

•   paid upon confirmation of legal closing and funding

EXAMPLE # 1:

Pam finds a buyer who will pay less than the guaranteed offer from the relocation service. She doesn’t reject the contract to hold out for the higher price and calls her Prudential counselor to review the offer. She knows that as long as the buyer’s contract is 97 percent or more of the relocation service’s offer, she will still receive the higher guaranteed offer. The company wants the home to sell and encourages employees to bring all reasonable offers to the relocation service.

Pam’s guaranteed offer $100,000
Pam’s buyer $97,000

Pam’s equity will be based on the guaranteed $100,000 and will be eligible for a home sale bonus of $2,910 ($97,000 X 3%).

EXAMPLE # 2:

John finds a buyer who will pay more than the guaranteed offer from the relocation service. He doesn’t reject the contract from Prudential, and he calls his Prudential counselor to review the offer to make sure it will net him more and then simply amends the Prudential contract for the higher offer.

John’s guaranteed offer $100,000
John’s amended value $102,000

John’s equity will be based on the amended offer of $102,000 and will be eligible for a home sale bonus of $3,060 ($102,000 X 3%).

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6.   LOSS ON SALE — If the guaranteed offer or amended value of the old home is less than the original price, the company will offset the loss. To qualify, the employee must participate in the Home Marketing Assistance Program and market the home for at least 60 days. The employee will receive 100 percent of the loss, grossed up for taxes, which is calculated based on the difference between the original purchase price (based on closing statement) plus any eligible capital improvements and the greater of the guaranteed offer or amended value. If the employee built the home, an itemized list of building expenses and receipts are required to support original purchase price. The employee should call the Prudential counselor with questions regarding original purchase price and sale price definitions.

7.   SELLING ON YOUR OWN — If an employee decides to sell the home without the help of the relocation company, for a period of not more than one year from the date of transfer, the company will authorize payment of various fees and charges involved in the sale of the employee’s residence. These expenses may vary by state. Therefore, before executing an agreement, the employee should contact the Prudential counselor to ensure that these costs will be covered. Such expenses may include:

•   attorney’s fees, escrow services charges

•   revenue stamps

•   transfer taxes

•   settlement, recording and processing fees

•   sale commission if paid to a licensed real estate broker and limited to the prevailing normal rate in the area

•   mortgage prepayment penalty in accordance with theterms of the mortgage

•   prepayment penalty on existing primary or secondary loan upon proper verification from the institution.

The company will not reimburse for mortgage discount points or other closing costs which are agreed to be paid on behalf of the purchaser.

Costs associated with selling expenses and reimbursed outside the relocation company are not grossed up for taxes.

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E.   PURCHASE OF NEW RESIDENCE

1.

The Prudential counselor will coordinate the assistance required for the employee to purchase his/her new residence. It is important that the employee seek assistance from the Prudential counselor before executing any agreement to purchase a new home.

2.

The company will reimburse for various fees and charges which the employee is required by law or local practice to pay in connection with the purchase of a home at the new location. This amount will be grossed up for taxes. The provision will be applicable for a period of not more than one year from the date of transfer. The employee must check with the Prudential counselor for verification of allowable reimbursements. Such expenses may include:

•   attorney’s fees, escrow service charge

•   up to 2 percent discount points including loan origination fee

•   recording fees

•   title insurance policy/binder

•   transfer taxes

•   credit report

•   fees for home appraisals if required by the lending institution before a mortgage loan will be approved.

•   inspection fees (termite, structural) when normal, customary or required by the lender

3.   Equity Loan — Prudential will provide an equity loan for the purpose of purchasing a home at the new work location. In order to receive an equity loan, a copy of a fully executed purchase agreement or binder for the new residence must be submitted before any money is advanced. The loan will not be for more than 120 days, and the interest on the loan will be paid by the company. The maximum loan amount may not exceed 90 percent of the equity in the old home as determined by appraisals. The employee will be required to sign an equity loan note, which will become due and payable at the time full equity is disbursed and Prudential acquires the employee’s property.

F.   MORTGAGE SUBSIDY

In order to ease the burden which occurs in those cases in which the transferred employee has a home mortgage at the previous location at a lesser interest rate than he or she is able to obtain on a home mortgage at the new location, a mortgage subsidy may be available if the following qualifications are met:

•   Old mortgage interest rate is at least 7 percent (if the old rate is less than 7 percent, then 7 percent will be used).

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•   New interest rate is at least 1 percent higher than the old. New mortgage loan must be the same type as the old one (i.e., if the old loan was a 30-year fixed rate, the new loan must be a 30-year fixed rate).

The amount of subsidy is based on the percentage difference between the old and the new mortgages according to the following schedule:

•   1 percent difference = 1 point

•   3 percent difference = 4 points

•   4 percent difference = 6 points

•   5 percent difference = 8 points

•   6 percent difference = 10 points

	Each point is equal to 1 percent of the mortgage.
	The subsidy is paid in one lump sum and is not grossed up for taxes. The Prudential counselor will advise the employee if he/she is eligible.
G.	RENTAL OVERLAP AND LEASE CANCELLATION The company will reimburse rental overlap not to exceed one month’s rent when an employee locates a rental home or apartment at the new location before being able to vacate the former residence. The company will reimburse the employee for the actual expense (grossed up for taxes) of a lease cancellation for up to two months’ rent if required.
H.	RENTAL ASSISTANCE The Prudential counselor will provide information on the local practice and procedures for renting a home in the destination area. The counselor will recommend a real estate broker or rental agency in the destination area to provide the employee with information packages on orientation tours of communities. Prudential will also work with the broker to guide the employee through the rental and lease execution process.
I.	SPOUSE ASSISTANCE An employee’s spouse may find it necessary to give up a job because of the relocation. There are often additional expenses associated with securing a position in the new location. The company will reimburse up to $1,000, not grossed up for taxes, for expenses associated with the spouse securing a position in the new location. This includes costs associated with such items as:

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•   requirements for special certifications

•   specialized training

•   placement counseling

	The employee should ask the Prudential counselor to clarify the costs that qualify for reimbursement.
J.	TAX ASSISTANCE
	Most of the money the company pays to an employee for relocation expenses is considered by the Internal Revenue Service (and many states) as income and is therefore taxable. The company will assist the employee by paying the tax (i.e., provide extra income, also referred to as “gross-up”) on most expenses considered non-deductible which cause the employee tax liability.
	The following information lists those items that are grossed up and those items that are not grossed up for federal and FICA tax purposes. Gross-up for state and local taxes will depend on the various state and local laws.
	Items grossed up include:

•   incidental allowance

•   homefinding allowance

•   temporary living allowance

•   loss protection

•   lease cancellation

•   mobile home lump sum payment

•   closing costs at new location

•   meals for final move to new location

•   mileage that is not deductible

•   storage over 30 days and up to 60 days

Items not grossed up include:

•   mortgage subsidy

•   spousal assistance

•   home sale bonus

•   reimbursed costs (associated with selling expenses and reimbursed outside the relocation company) for self closing

•   lump sum for self move

•   household goods shipment — excluded from income

•   transportation to new location (except meals) — excluded from income

•   mileage that is deductible — excluded from income

•   storage less than 30 days — excluded from income

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	Discount points on new home purchase will be tax assisted at time of payment, subject to year-end tax reconciliation.
	Tax assistance includes federal, state, local and FICA (Medicare and social security) and is based on the transferred employee’s total compensation from company sources only. Other sources of income, including spouse’s income, will not be included in this process. Year-end tax reconciliation is performed and, therefore, may possibly cause adjustments to be made to employee’s income and/or taxes at the end of the year.
	If the employee has any questions concerning taxes, he/she should seek professional income tax accountant/consultant guidance.
K.	PURCHASE OF HOUSTON RESIDENCE
	The company will agree to purchase the home acquired by an employee in connection with the transfer to Houston for an amount equal to the greater of (1) the appraised value (as determined under paragraph D.3 regarding “guaranteed offer”), or (2) the amount of the employee’s investment (plus a tax gross-up for applicable taxes that may be due on the difference between the market value and the investment) (as determined under paragraph D.6 regarding “loss on sale”). The company’s obligation to purchase a residence under this provision applies if (a) the employee is transferred by the company, (b) there is a change of control of El Paso Energy Corporation, or (3) the employee dies, retires or becomes permanently disabled. This benefit applies only to executive officers at grade level D or higher.

Major deviations from policy require approval by the senior functional officer of Human Resources and Administration of El Paso Energy Corporation.

This practice does not constitute nor imply a contract between the company and its employees or their dependents. It has been voluntarily adopted for the sole and exclusive use of the company and may be amended or withdrawn at any time without prior notice.

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EX-10.S

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EXHIBIT 10.S

EXECUTIVE AWARD PLAN
OF
SONAT INC.
(AS AMENDED AND RESTATED AS OF JULY 23, 1998)

I. GENERAL

1.1 PURPOSE OF THE PLAN

     The Executive Award Plan (the “Plan”) of Sonat Inc. (the “Company”) is intended to advance the best interests of the Company and its subsidiaries by providing key employees with additional incentives through the grant of options (“Options”) to purchase shares of Common Stock of the Company (“Common Stock”) and through the award of shares of restricted Common Stock (“Restricted Stock”), thereby increasing the personal stake of such employees in the continued success and growth of the Company and encouraging them to remain in the employ of the Company.

     The Plan was adopted effective May 1, 1981, and has been amended at various times. The provisions of the Plan as hereby amended and restated may, at the discretion of the Committee referred to below, be made available to all grants outstanding on the effective date of this Amendment and Restatement, and all awards granted after such date, except that no such provision shall alter any outstanding grant in a manner unfavorable to the holder thereof without the written consent of the holder.

1.2 ADMINISTRATION OF THE PLAN

     (A) The Plan shall be administered by the Executive Compensation Committee or other designated committee (the “Committee”) of the Board of Directors of the Company (the “Board of Directors”) which shall consist of at least three Directors all of whom are not eligible to participate in the Plan and are “disinterested” within the meaning of Rule 16b-3 under the Securities Exchange Act of 1934 (the “Exchange Act”). The Committee shall have authority to interpret conclusively the provisions of the Plan, to adopt such rules and regulations for carrying out the Plan as it may deem advisable, to decide conclusively all questions of fact arising in the application of the Plan, and to make all other determinations necessary or advisable for the administration of the Plan. All decisions and acts of the Committee shall be final and binding upon all affected Plan participants.

     (b) The Committee shall meet once each fiscal year, and at such additional times as it may determine or at the request of the chief executive officer of the Company, to designate the eligible employees, if any, to be granted awards under the Plan and the type and amount of such awards and the time when awards will be granted. All awards granted under the Plan shall be on the terms and subject to the conditions hereinafter provided.

1.3 ELIGIBLE PARTICIPANTS

     Key employees, including officers, of the Company and its subsidiaries, and of partnerships or joint ventures in which the Company and its subsidiaries have a significant ownership interest as determined by the Committee (all of such subsidiaries, partnerships and joint ventures being referred to as “Subsidiaries”) shall be eligible to participate in the Plan. Directors who are not employees of the Company or its Subsidiaries shall not be eligible to participate in the Plan.

1.4 AWARDS UNDER THE PLAN

     Awards under the Plan may be in the form of (i) Options to purchase shares of Common Stock, (ii) Stock Appreciation Rights and Limited Stock Appreciation Rights which may be issued in tandem with such Options, (iii) shares of Restricted Stock, and (iv) Supplemental Payments which may be awarded with respect to Options, Stock Appreciation Rights, Limited Stock Appreciation Rights, and Restricted Stock, or (v) any combination of the foregoing.

1.5 SHARES SUBJECT TO THE PLAN

     The aggregate number of shares of Common Stock which may be issued with respect to Options or Restricted Stock granted after April 27, 1995 (including Stock Appreciation Rights, Limited Stock Appreciation Rights and Supplemental Payments related thereto) shall not exceed (i) 4,000,000 shares plus (ii) the number of shares previously authorized for use in the Plan which have not been issued or have again become available for grants pursuant to the following paragraph. At no time shall the number of shares issued plus the number of shares subject to outstanding awards under the Plan exceed the number of shares that may be issued under the Plan. Options with respect to more than 250,000 shares of Common Stock shall not be granted to any optionee in any 12-month period. Shares distributed pursuant to the Plan may consist of authorized but unissued shares or treasury shares of the Company, as shall be determined from time to time by the Board of Directors.

     If any Option under the Plan shall expire, terminate or be canceled (except upon the holder’s exercise of a related Stock Appreciation Right or Limited Stock Appreciation Right) for any reason without having been exercised in full, or if any shares of Restricted Stock shall be forfeited to the Company, the unexercised Options and forfeited shares of Restricted Stock shall not count against the above limit and shall again become available for grants under the Plan (regardless of whether the holder of such Options or shares received dividends or other economic benefits with respect to such Options or shares). Shares of Common Stock equal in number to the shares surrendered in payment of the option price, and shares of Common Stock which are withheld in order to satisfy federal, state or local tax liability, shall not count against the above limit and shall again become available for grants under the Plan. Notwithstanding the foregoing, any shares which were authorized for issuance under the Plan as in effect on April 25, 1985 shall not be available for issuance with respect to awards granted after April 24, 1995.

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1.6 OTHER COMPENSATION PROGRAMS

     The existence and terms of the Plan shall not limit the authority of the Board of Directors in compensating employees of the Company and its subsidiaries in such other forms and amounts, including compensation pursuant to any other plans as may be currently in effect or adopted in the future, as it may determine from time to time.

II. STOCK OPTIONS

2.1 TERMS AND CONDITIONS OF OPTIONS

     Subject to the following provisions, all Options granted under the Plan shall be in such form and shall have such terms and conditions as the Committee, in its discretion, may from time to time determine.

     (a) Option Price. The option price per share shall not be less than the fair market value of the Common Stock (as determined by the Committee) on the date the Option is granted.

     (b) Term of Option. The term of an Option shall not exceed ten years from the date of grant, and, notwithstanding any other provision of this Plan, no Option shall be exercised after the expiration of its term.

     (c) Exercise of Options. Options shall be exercisable at such time or times and subject to such terms and conditions as the Committee shall specify in the Option grant. The Committee shall have discretion to at any time declare all or any portion of the Options held by any optionee to be immediately exercisable. An Option may be exercised in accordance with its terms as to any or all shares purchasable thereunder.

     (d) Payment for Shares. Payment for shares as to which an Option is exercised shall be made in such manner and at such time or times as shall be provided by the Committee in the Option grant. Payment may be made in cash or in such other manner as the Committee in its discretion may authorize.

     (e) Nontransferability of Options. No Option or any interest therein shall be transferable by the optionee other than by will or by the laws of descent and distribution. During an optionee’s lifetime, all Options shall be exercisable only by such optionee or by the guardian or legal representative of the optionee.

     (f) Shareholder Rights. The holder of an Option shall, as such, have none of the rights of a shareholder.

     (g) Termination of Employment. The Committee shall have discretion to specify in the Option grant or an amendment thereof, provisions with respect to the

3

period, not extending beyond the term of the Option, during which the Option may be exercised following the optionee’s termination of employment.

     (h) Change of Control. Notwithstanding the exercisability schedule governing any Option, upon the occurrence of a Change of Control (as defined in Section 4.9) all Options outstanding at the time of such Change of Control and held by optionees who are employees of the Company or its Subsidiaries at the time of the Change of Control shall become immediately exercisable and, unless the optionee agrees otherwise in writing, shall remain exercisable for a period of three years following the optionee’s termination of employment or such longer period as may be provided in the Option, but in no event beyond the term of the Option established pursuant to Section 2.1(b).

2.2 STOCK APPRECIATION RIGHTS IN TANDEM WITH OPTIONS

     (a) The Committee may, either at the time of grant of an Option or at any time during the term of the Option, grant Stock Appreciation Rights or Limited Stock Appreciation Rights with respect to all or any portion of the shares of Common Stock covered by such Option. A Stock Appreciation Right may be exercised at any time the Option to which it relates is then exercisable. A Limited Stock Appreciation Right may be exercised only within 60 days after the occurrence of a Change of Control. A Stock Appreciation Right or a Limited Stock Appreciation Right may only be exercised to the extent the Option to which it relates is exercisable, and shall be subject to the conditions applicable to such Option. When a Stock Appreciation Right or Limited Stock Appreciation Right is exercised, the Option to which it relates shall cease to be exercisable to the extent of the number of shares with respect to which the Stock Appreciation Right or Limited Stock Appreciation Right is exercised. Similarly, when an Option is exercised, the Stock Appreciation Rights or Limited Stock Appreciation Rights relating to the shares covered by such Option exercise shall terminate. Any Stock Appreciation Right which is outstanding on the last day of the term of the related Option (as determined pursuant to Section 2.1(b)) shall be automatically exercised on such date without any action by the optionee.

     (b) Upon exercise of a Stock Appreciation Right, the holder shall receive, for each share with respect to which the Stock Appreciation Right is exercised, an amount (the “Appreciation”) equal to the difference between the option price per share of the Option to which the Stock Appreciation Right relates and the fair market value (as determined by the Committee) of a share of Common Stock on the date of exercise of the Stock Appreciation Right. The Appreciation shall be payable in cash, Common Stock, or a combination of both, at the option of the Committee, and shall be paid within 30 days of the exercise of the Stock Appreciation Right.

     (c) Notwithstanding the foregoing, if a Stock Appreciation Right is exercised within 60 days after the occurrence of a Change of Control, in addition to the Appreciation and any Supplemental Payment (as defined in Section 2.3) to which the holder is entitled, the holder shall receive (in cash, in Common Stock, or a combination of both, at the discretion of the Committee) (1) the amount by which the greater of

4

(a) the highest market price per share of Common Stock during the 60-day period preceding exercise of the Stock Appreciation Right or (b) the highest price per share of Common Stock (or the cash- equivalent thereof as determined by the Board of Directors) paid by an acquiring person during the 60-day period preceding a Change of Control, exceeds the fair market value of a share of Common Stock on the date of exercise of the Stock Appreciation Right, plus (2) if the holder is entitled to a Supplemental Payment, an additional payment, calculated under the same formula as used for calculating such holder’s Supplemental Payment, with respect to the amount referred to in clause (1) of this sentence.

     (d) Upon exercise of a Limited Stock Appreciation Right, the holder shall receive, for each share with respect to which the Limited Stock Appreciation Right is exercised, the sum of (i) the Appreciation, as defined in Section 2.2(b); (ii) any Supplemental Payment (as defined in Section 2.3) to which the holder is entitled with respect to the Appreciation; (iii) the amount by which the greater of (a) the highest market price per share of Common Stock during the 60-day period preceding exercise of the Limited Stock Appreciation Right or (b) the highest price per share of Common Stock (or the cash-equivalent thereof as determined by the Board of Directors) paid by an acquiring person during the 60-day period preceding a Change of Control, exceeds the fair market value of a share of Common Stock on the date of exercise of the Limited Stock Appreciation Right; and (iv) if the holder is entitled to a Supplemental Payment, an additional payment, calculated under the same formula as used for calculating such holder’s Supplemental Payment, with respect to the amount referred to in clause (iii) of this sentence. All of such amounts shall be paid within 30 days of the exercise of the Limited Stock Appreciation Right, and shall be paid in cash, in Common Stock, or a combination of both, at the discretion of the Committee.

2.3 SUPPLEMENTAL PAYMENT ON EXERCISE OF OPTIONS OR STOCK APPRECIATION RIGHTS

     The Committee, either at the time of grant or at the time of exercise of any Option or related Stock Appreciation Right or Limited Stock Appreciation Right, may provide for a supplemental payment (the “Supplemental Payment”) by the Company to the optionee with respect to the exercise of any Option or related Stock Appreciation Right or Limited Stock Appreciation Right. The Supplemental Payment shall be in the amount specified by the Committee, which shall not exceed, but may be equal to, the amount necessary to pay the federal income tax payable with respect to both exercise of the Option or related Stock Appreciation Right or Limited Stock Appreciation Right and receipt of the Supplemental Payment, assuming the optionee is taxed at the maximum effective federal income tax rate applicable thereto. The Supplemental Payment shall be paid in cash, Common Stock, or a combination of both, at the option of the Committee. The Supplemental Payment shall be paid within 30 days of the date of exercise of an Option or Stock Appreciation Right or Limited Stock Appreciation Right (or, if later, within 30 days of the date on which income is recognized for federal income tax purposes with respect to such exercise).

5

2.4 STATUTORY OPTIONS

     Subject to the limitations on Option terms set forth in Section 2.1, the Committee shall have the authority to grant (i) incentive stock options within the meaning of Section 422 of the Code and (ii) Options containing such terms and conditions as shall be required to qualify such Options for preferential tax treatment under the Code as in effect at the time of such grant. Options granted pursuant to this Section 2.4 may contain such other terms and conditions permitted by Article II of this Plan as the Committee, in its discretion, may from time to time determine (including, without limitation, provision for Stock Appreciation Rights, Limited Stock Appreciation Rights and Supplemental Payments), to the extent that such terms and conditions do not cause the Options to lose their preferential tax treatment. To the extent the Code and Regulations promulgated thereunder require a plan to contain specified provisions in order to qualify options for preferential tax treatment, such provisions shall be deemed to be stated in this Plan.

III. RESTRICTED STOCK

3.1 TERMS AND CONDITIONS OF RESTRICTED STOCK AWARDS

     Subject to the following provisions, all awards of Restricted Stock shall be in such form and shall have such terms and conditions as the Committee, in its discretion, may from time to time determine:

     (a) The Restricted Stock award shall specify the number of shares of Restricted Stock to be awarded, the price, if any, to be paid by the recipient of the Restricted Stock, and the date or dates on which the Restricted Stock will vest. The vesting of Restricted Stock may be conditioned upon the completion of a specified period of service with the Company or its Subsidiaries, upon the attainment of specified performance goals, or upon such other criteria as the Committee may determine in its sole discretion.

     (b) Stock certificates representing the Restricted Stock granted to an employee shall be registered in the employee’s name. Such certificates shall either be held by the Company on behalf of the employee, or delivered to the employee bearing a legend to restrict transfer of the certificate until the Restricted Stock has vested, as determined by the Committee. The Committee shall determine whether the employee shall have the right to vote and/or receive dividends on the Restricted Stock before it has vested. No share of Restricted Stock may be sold, transferred, assigned, or pledged by the employee until such share has vested in accordance with the terms of the Restricted Stock award. In the event of an employee’s termination of employment before all of his Restricted Stock has vested, or in the event other conditions to the vesting of Restricted Stock have not been satisfied prior to any deadline for the satisfaction of such conditions set forth in the award, the shares of Restricted Stock which have not vested shall be forfeited and any purchase price paid by the employee shall be

6

returned to the employee. At the time Restricted Stock vests (and, if the employee has been issued legended certificates of Restricted Stock, upon the return of such certificates to the Company), a certificate for such vested shares shall be delivered to the employee (or the beneficiary designated by the employee in the event of death), free of all restrictions.

     (c) Notwithstanding the vesting conditions set forth in the Restricted Stock award, (i) the Committee may in its discretion accelerate the vesting of Restricted Stock at any time, and (ii) all shares of Restricted Stock shall vest upon a Change of Control of the Company.

3.2 SUPPLEMENTAL PAYMENT ON VESTING OF RESTRICTED STOCK

     The Committee, either at the time of grant or at the time of vesting of Restricted Stock, may provide for a Supplemental Payment by the Company to the employee in an amount specified by the Committee which shall not exceed, but may be equal to, the amount necessary to pay the federal income tax payable with respect to both the vesting of the Restricted Stock and receipt of the Supplemental Payment, assuming the employee is taxed at the maximum effective federal income tax rate applicable thereto and has not elected to recognize income with respect to the Restricted Stock before the date such Restricted Stock vests. The Supplemental Payment shall be paid within 30 days of each date that Restricted Stock vests. The Supplemental Payment shall be paid in cash, Common Stock, or a combination of both, at the discretion of the Committee.

IV. ADDITIONAL PROVISIONS

4.1 GENERAL RESTRICTIONS

     Each award under the Plan shall be subject to the requirement that, if at any time the Committee shall determine that (i) the listing, registration or qualification of the shares of Common Stock subject or related thereto upon any securities exchange or under any state or federal law, or (ii) the consent or approval of any government regulatory body, or (iii) an agreement by the recipient of an award with respect to the disposition of shares of Common Stock is necessary or desirable (in connection with any requirement or interpretation of any federal or state securities law, rule or regulation) as a condition of, or in connection with, the granting of such award or the issuance, purchase or delivery of shares of Common Stock thereunder, such award may not be consummated in whole or in part unless such listing, registration, qualification, consent, approval or agreement shall have been effected or obtained free of any conditions not acceptable to the Committee.

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4.2 ADJUSTMENTS FOR CHANGES IN CAPITALIZATION

     In the event of a reorganization, recapitalization, stock split, stock dividend, combination of shares, rights offer, liquidation, dissolution, merger, consolidation, spin-off, sale of assets, payment of an extraordinary cash dividend, or any other change in or affecting the corporate structure or capitalization of the Company, the Committee shall make appropriate adjustment in the number and kind of shares authorized by the Plan (including any limitations on individual awards), in the number, price or kind of shares covered by the awards and in any outstanding awards under the Plan.

4.3 AMENDMENTS

     (a) The Board of Directors may amend the Plan from time to time. No such amendment shall require approval by the stockholders unless stockholder approval is required by applicable law or stock exchange requirements.

     (b) The Committee shall have the authority to amend any grant to include any provision which, at the time of such amendment, is authorized under the terms of the Plan; provided, however, that (1) no outstanding award may be revoked or altered in a manner unfavorable to the holder without the written consent of the holder, and (2) no outstanding Option may be altered in a manner that reduces the option price (except as provided in Section 4.2).

4.4 CANCELLATION OF AWARDS

     Any award granted under the Plan may be canceled at any time with the consent of the holder and a new award may be granted to such holder in lieu thereof, which award may, in the discretion of the Committee, be on more favorable terms and conditions than the canceled award; provided, however, that any Option that is granted in lieu of a canceled Option shall have an option price at least equal to the option price of the canceled Option.

4.5 WITHHOLDING

     (a) Whenever the Company proposes or is required to issue or transfer shares of Common Stock under the Plan, the Company shall have the right to require the holder to remit to the Company an amount sufficient to satisfy any federal, state or local withholding tax liability prior to the delivery of any certificate for such shares. Whenever under the Plan payments are to be made in cash, such payments shall be net of an amount sufficient to satisfy any federal, state or local withholding tax liability.

     (b) An employee entitled to receive Common Stock under the Plan who has not received a cash Supplemental Payment may elect to have the federal, state and local tax liability (or a specified portion thereof) with respect to such Common Stock satisfied by having the Company withhold from the shares otherwise deliverable to the employee shares of Common Stock having a value equal to the amount of the tax liability to be satisfied with respect to the Common Stock. An election to have all or a

8

portion of the tax liability satisfied using Common Stock shall comply with such requirements as may be imposed by the Committee and shall be subject to the disapproval of the Committee (if expressed prior to the making of such election).

4.6 NON-ASSIGNABILITY

     Except as expressly provided in the Plan, no award under the Plan shall be assignable or transferable by the holder thereof except by will or by the laws of descent and distribution. During the life of the holder, awards under the Plan shall be exercisable only by such holder or by the guardian or legal representative of such holder.

4.7 NON-UNIFORM DETERMINATIONS

     Determinations by the Committee under the Plan (including, without limitation, determinations of the persons to receive awards; the form, amount and timing of such awards; the terms and provisions of such awards and the agreements evidencing same; and provisions with respect to termination of employment) need not be uniform and may be made by it selectively among persons who receive, or are eligible to receive, awards under the Plan, whether or not such persons are similarly situated.

4.8 NO GUARANTEE OF EMPLOYMENT

     The grant of an award under the Plan shall not constitute an assurance of continued employment for any period.

4.9 CHANGE OF CONTROL

     A “Change of Control” shall mean:

     (i) The acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Exchange Act) (a “Person”) of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 20% or more of either (1) the then outstanding shares of common stock of the Company (the “Outstanding Common Stock”) or (2) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors (the “Outstanding Voting Securities”); provided, however, that for purposes of this subsection (i), the following acquisitions shall not constitute a Change of Control: (A) any acquisition directly from the Company, (B) any acquisition by the Company, (C) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company or (D) any acquisition by any corporation pursuant to a transaction which complies with clauses (A), (B) and (C) of subsection (iii); or

     (ii) Individuals who, as of December 1, 1995, constitute the Board of Directors (the “Incumbent Board”) cease for any reason to constitute at least a majority of the Board of Directors; provided, however, that any individual becoming

9

a director subsequent to such date whose election, or nomination for election by the Company’s shareholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board of Directors; or

     (iii) Consummation of a reorganization, merger or consolidation or sale or other disposition of all or substantially all of the assets of the Company (a “Business Combination”), in each case, unless, following such Business Combination, (A) all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Common Stock and Outstanding Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination (including, without limitation, a corporation which as a result of such transaction owns the Company or all or substantially all of the Company’s assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership, immediately prior to such Business Combination, of the Outstanding Common Stock and Outstanding Voting Securities, as the case may be, (B) no Person (excluding any corporation resulting from such Business Combination or any employee benefit plan (or related trust) of the Company or such corporation resulting from such Business Combination) beneficially owns, directly or indirectly, 20% or more of, respectively, the then outstanding shares of common stock of the corporation resulting from such Business Combination or the combined voting power of the then outstanding voting securities of such corporation except to the extent that such ownership existed prior to the Business Combination and (C) at least a majority of the members of the board of directors of the corporation resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement, or of the action of the Board of Directors, providing for such Business Combination.

4.10 DURATION AND TERMINATION

     (a) The Plan shall be of unlimited duration. Notwithstanding the foregoing, no incentive stock option (within the meaning of Section 422 of the Code) shall be granted under the Plan after April 26, 2005, but awards granted prior to such date may extend beyond such date, and the terms of this Plan shall continue to apply to all awards granted hereunder.

     (b) The Board of Directors may discontinue or terminate the Plan at any time. Such action shall not impair any of the rights of any holder of any award outstanding on the date of the Plan’s discontinuance or termination without the holder’s written consent.

10

     This document incorporates into a single document the provisions of the Plan as amended as of July 23, 1998.

     IN WITNESS WHEREOF, this document has been executed as of July 23, 1998.

	SONAT INC.
by:	/s/ RONALD L. KUEHN, JR.
	Ronald L. Kuehn, Jr.
	Chairman of the Board,
	President and Chief Executive Officer

11

AMENDMENT TO EXECUTIVE AWARD PLAN
AND CERTAIN STOCK OPTIONS GRANTED THEREUNDER

     The Executive Award Plan of Sonat Inc., as amended and restated as of July 23, 1998 (the “Plan”), and each Affected Option (as defined below) that has been granted thereunder, are each hereby amended as set forth below, effective as May 27, 1999.

          1. A new Section 2.2(e) is hereby added to the Plan, reading in its entirety as follows:

     (e) (i) Notwithstanding the foregoing, the provisions of this Section 2.2(e) shall apply to the exercise of any Stock Appreciation Right or Limited Stock Appreciation Right in connection with the merger (the “Merger”) between the Company and El Paso Energy Corporation (“El Paso”) pursuant to the Second Amended and Restated Agreement and Plan of Merger, as amended from time to time (the “Merger Agreement”) dated as of March 3, 1999 by and between the Company and El Paso.

     (ii) All Limited Stock Appreciation Rights shall be exercisable only at the time of the Merger and shall, if not so exercised, terminate immediately after the Merger. In addition, the amounts payable pursuant to Section 2.2(d) in connection with such exercise shall be determined by (x) excluding the amount described in clause (iii) thereof, (y) including an additional amount equal to the value (if any) of (I) the right of the holder to receive a payment based upon the pricing mechanism set forth in said clause (iii) and (II) the right of the holder to exercise the Limited Stock Appreciation Right during the 60-day period following the Merger, which rights (the “Rights”) are eliminated pursuant to this Section 2.2(e), and (z) determining the amount described in clause (iv) thereof by reference to the value of the Rights determined in accordance with (y) hereof rather than by reference to the amount referred to in clause (iii) of Section 2.2(d). The value of the Rights shall be determined by the Committee based upon the advice of Merrill Lynch, Pierce, Fenner & Smith Incorporated and Donaldson, Lufkin & Jenrette Securities Corporation.

     (iii) All Stock Appreciation Rights shall be exercisable at the time of the Merger and, if so exercised, the amounts payable pursuant to Section 2.2(c) in connection with such exercise shall be determined by: (A) excluding the amount described in clauses (a) and (b) thereof, (B) including an additional amount determined in the same manner as set forth in clause (y) of Section 2.2(e)(ii) hereof with respect to Limited Stock Appreciation Rights; and (C) determining the amount described in clause (2) thereof by reference to the value of the Rights determined in accordance with clause (B) hereof rather than by reference to the amount

12

13

described in clauses (a) and (b) thereof. If a Stock Appreciation Right is exercised at any time other than at the time of the Merger, Section 2.2(c) shall not apply to such exercise.

     (iv) The consideration to be paid pursuant to Sections 2.2(c) and (d) as modified hereby (including the Supplemental Payment (if any)) shall be paid in the form of common stock of El Paso, based upon the value of such common stock on the day of the Merger.

          2. Each outstanding Option granted under the Plan that includes a Stock Appreciation Right or a Limited Stock Appreciation Right (or both) (an “Affected Option”) is hereby amended to incorporate the provisions of new Section 2.2(e) of the Plan set forth above.

          3. It is acknowledged and agreed that as a result of the amendments set forth above: (i) with respect to an Affected Option with an associated Limited Stock Appreciation Right, to the extent that the holder of such Affected Option does not exercise the associated Limited Stock Appreciation Right at the time of the Merger, the Affected Option will be convened into an option to acquire common stock of El Paso pursuant to Section 2.7 of the Merger Agreement, which new option will not include a Limited Stock Appreciation Right; and (ii) with respect to any Affected Option with an associated Stock Appreciation Right, to the extent that the holder of such Affected Option does not exercise the associated Stock Appreciation Right at the time of the Merger, the Affected Option will be converted into an option to acquire common stock of El Paso pursuant to Section 2.7 of the Merger Agreement, which new option will include an associated Stock Appreciation Right to which Section 2.2(c) of the Plan does not apply.

		SONAT INC.
		By:	/s/ Beverely T. Krannich
Consented, agreed to and accepted:
EL PASO ENERGY CORPORATION
By:	/s/ Britton White Jr.
	Britton White Jr., Esq.
	Date: October 25, 1999

EX-21

El PASO CORPORATION
OWNERSHIP LIST
as of December 31, 2004 EXHIBIT 21

		%
ENTITY NAME	OWNER	OWNERSHIP
3082263 Nova Scotia Limited (Nova Scotia)	El Paso Production Oil & Gas Company		100
Acajutla (Cayman) Company (Cayman Islands)	El Paso Energy Acajutla Company		100
Agropecuaria Santo Antonio Ltda. (Brazil)	El Paso Energy International do Brasil Ltda.		.0002
	Termo Norte Energia Ltda.		99.9997
	Unaffiliated Parties		.0002
Agua del Cajon (Cayman) Company (Cayman Islands)	El Paso Neuquen Holding Company		100
	Note: EPED B Company owns 100% of the Cumalative Preferred Stock.
Aguaytia Energy del Peru S.R. Ltda. (Peru)	Aguaytia Energy L.L.C.		22.0454
	Unaffiliated Parties		77.0546
Aguaytia Energy L.L.C. (DE)	EPED Aguaytia Company		24.3
	The Maple Gas Development Corporation		16.96
	Unaffiliated Parties		58.74
Alpheus Communications, L.P. (DE)	Zipline, L.L.C. (GP)		1
	El Paso Telecom, L.L.C. (LP)		71
	Unaffiliated Parties (LP)		28
American Natural Resources Company (DE)	El Paso CNG Company, L.L.C.		100
Americas Generation Corp. (Panama)	Americas Holding Corp.		100
	Coastal Power Panama Investor, S.A.		49.9
Americas Holding Corp. (Panama)	Unaffiliated Parties		50.1
Amethyst Power Holdings, L.L.C. (DE)	Garnet Power Holdings, L.L.C.		100
Andros Ltd. (Cayman Islands)	Coastal Securities Company Limited		100
	El Paso Midwest Company		50
ANR Advance Holdings, Inc. (DE)	Unaffiliated Parties		50
ANR Alliance Pipeline Company Canada, Inc.	ANR Pipeline Company		100
(New Brunswick)
ANR Blue Lake Company (DE)	ANR Storage Company		100
ANR Capital Corporation (DE)	ANR Pipeline Company		100
ANR Development Corporation (DE)	El Paso CGP Company		100
ANR Eaton Company (MI)	ANR Storage Company		100
ANR Jackson Company (DE)	ANR Storage Company		100
ANR Northeastern Gas Storage Company (DE)	ANR Storage Company		100
ANR Pipeline Company (DE)	El Paso ANR Investments, L.L.C.		100
ANR Real Estate Corporation (DE)	ANR Development Corporation		100
ANR Storage Company (MI)	El Paso ANRS Investments, L.L.C.		100
ANR Transportation Services Company (DE)	El Paso CGP Company		100
ANR Venture Eagle Point Company (DE)	American Natural Resources Company		100
ANR Venture Management Company (DE)	American Natural Resources Company		100
ANR Western Coal Development Company (DE)	El Paso CNG Company, L.L.C.		100
ANR Western Storage Company (DE)	ANR Storage Company		100
ANRV Eagle Point, L.P. (DE)	ANRV-EP, Inc. (GP)		1
	Coastal Eagle Point Oil Company (LP)		99
ANRV-EP, Inc. (DE)	El Paso CGP Company		100
Aquamarine Power Holdings, L.L.C. (DE)	Diamond Power Holdings, L.L.C.		100
Arena Power, Ltd. (Cayman Islands)	Coastal Power International IV Ltd.		100
Arizona LNG, L.L.C. (NV)	El Paso Field Services, L.P.		100
BBPP Holdings Ltda. (Brazil)	EPIC Gas International Servicos do Brasil Ltda.		33.3333
	Unaffiliated Parties		66.6667
Bear Creek Storage Company (LA Partnership)	Tennessee Storage Company		50
	Southern Gas Storage Company		50
Berkshire Feedline Acquisition L.P. (MA)	El Paso Energy Pittsfield Corporation		50

With respect to legal entities which are not wholly owned by El Paso Corporation or its wholly owned subsidiaries, we make no representations as to the accuracy or completeness of information provided, including without limitation, the identification of any other affiliates of those non-wholly owned entities whether or not such affiliates are named herein.

		%
ENTITY NAME	OWNER	OWNERSHIP
	Unaffiliated Parties		50
Berkshire Power Company, LLC (MA)	El Paso Berkshire Power I Company, L.L.C.		56.4
	Unaffiliated Parties		43.6
Black Warrior Methane Corp. (AL)	El Paso Production Company		50
	Unaffiliated Parties		50
Black Warrior Transmission Corp. (AL)	El Paso Production Company		50
	Unaffiliated Parties		50
Blue Lake Gas Storage Company (MI)	ANR Blue Lake Company		75
	Unaffiliated Parties		25
Bonneville McKenzie Energy Corporation (Canada)	El Paso Merchant Energy North America Company		50
	Unaffiliated Parties		50
Canyon Creek Compression Company	CIG-Canyon Compression Company		15
(General Partnership) (IL)	Unaffiliated Parties		85
Capitol District Energy Center Cogeneration Associates	ANR Venture Management Company		50
(Joint Venture) (CT)	Mesquite Investors, L.L.C.		50
Cayger Finance Company (Cayman Islands)	EPED B Company		100
CDECCA Property Company, L.L.C. (DE)	Capitol District Energy Center Cogeneration		100
	Associates (Joint Venture)
CEBU Private Power Corporation (Philippines)	East Asia Utilities Corporation		80
	Unaffiliated Parties		20
Cedar Brakes I, L.L.C. (DE)	Mesquite Investors, L.L.C.		100
Cedar Brakes II, L.L.C. (DE)	Mesquite Investors, L.L.C.		100
CEG Finance Company Ltd. (Cayman Islands)	Coastal Power Nicaragua Holding Company Ltd.		90.9091
	Coastal Power Nicaragua Ltd.		9.0909
CFS Louisiana Midstream Company (DE)	El Paso Field Operations Company		100
Chaparral Investors, L.L.C. (DE))	El Paso Chaparral Holding Company (Class B)		19.6
	Limestone Electron, L.L.C. (Class A)		10.5
	Limestone Electron, L.L.C. (Class B)		69.9
Cheyenne Plains Gas Pipeline Company, L.L.C. (DE)	Cheyenne Plains Investment Company, L.L.C.		100
Cheyenne Plains Investment Company, L.L.C. (DE)	El Paso CNG Company, L.L.C.		100
CIG Field Services Company (DE)	Colorado Interstate Gas Company		100
CIG Gas Storage Company (DE)	El Paso CNG Company, L.L.C.		100
CIG Gas Supply Company (DE)	El Paso WIC Investments, L.L.C.		100
CIG Merchant Company (DE)	El Paso CGP Company		100
CIG Resources Company (DE)	El Paso CNG Company, L.L.C.		100
CIG-Canyon Compression Company (DE)	El Paso CNG Company, L.L.C.		100
CIGE Company (DE)	CIGE Holdco, Inc.		100
CIGE Holdco, Inc. (DE)	El Paso CGP Company		100
Citrine FC Company (Cayman Islands)	Emerald Finance, L.L.C.		100
Citrus Corp. (DE)	El Paso Citrus Holdings, Inc.		50
	Unaffiliated Parties		50
Citrus Energy Services, Inc. (DE)	Citrus Corp.		100
Citrus Trading Corp. (DE)	Citrus Corp.		100
Cliffside Helium LLC	CIG Resources Company		4
	Unaffiliated Parties		96
Cliffside Refiners, LP	Colorado Water Supply Company		3.96
	Cliffside Helium LLC		1
	Unaffiliated Parties		95.04
CNG Cayman Two Ltd. (Cayman Islands)	DBNGP Finance Company L.L.C.		76.92
	Unaffiliated Parties		23.08
CNG Labuan One (Australia)	CNG Cayman Two Ltd.		100
Coastal (Bermuda) Petroleum Limited (Bermuda)	Coastal Securities Company Limited		100
Coastal (Cayman Islands) Construction Company Ltd.	Coastal States Management Corporation		100

Page 2

		%
ENTITY NAME	OWNER	OWNERSHIP
(Cayman Islands)
Coastal (Rotterdam) B.V. (Netherlands)	El Paso Merchant Energy-Petroleum Company		100
Coastal Austral Ltd. (Cayman Islands)	Coastal Cape Horn Ltd.		100
Coastal Australia AC 96-3 Ltd. (Cayman Islands)	El Paso Production Oil & Gas Company		100
Coastal Australia AC 96-4 Ltd. (Cayman Islands)	El Paso Production Oil & Gas Company		100
Coastal Bangchak Power Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal BAS-97 Ltda. (Brazil)	El Paso Brazil, L.L.C.		99.8002
	El Paso Brazil Holdings Company		.1998
Coastal Belcher Petroleum Pte Ltd. (Singapore)	Coastal Securities Company Limited		.2797
	Coastal Cayman Finance Ltd.		99.7203
Coastal Bridger Lake Pipeline Corporation (DE)	El Paso Merchant Energy-Petroleum Company		100
Coastal Canada Gas Inc. (New Brunswick)	Cosbel Petroleum Corporation		100
Coastal Canada Gas Services, Inc. (New Brunswick)	El Paso CGP Company		100
Coastal Canada Petroleum, Inc. (New Brunswick)	Cosbel Petroleum Corporation		100
Coastal Cape Horn Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Cayman Finance Ltd. (Cayman Islands)	Coastal (Bermuda) Petroleum Limited		100
Coastal CFC Ltd. (Cayman Islands)	Coscol Petroleum Corporation		100
Coastal Chem, Inc. (DE)	El Paso CGP Company		100
Coastal Chile Agencia de Naves Limitada (Chile)	Coastal Petroleum N.V. Chile Limitada		99.9
	Coastal Petroleum N.V.		.1
Coastal Chile Comercial Limitada (Chile)	Coastal Petroleum N.V. Chile Limitada		99.9
	Coastal Petroleum N.V.		.1
Coastal Clark Investor Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Clark Manager Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Coal, Inc. (DE)	El Paso Coal Holding, L.L.C.		100
Coastal Development II Ltd. (Cayman Islands)	El Paso Production Oil & Gas Company		100
Coastal Development III Ltd. (Cayman Islands)	El Paso Production Oil & Gas Company		100
Coastal do Brasil Ltda. (Brazil)	Coastal States Management Corporation		99.9999
	El Paso Merchant Energy-Petroleum Company		.0001
Coastal Eagle Point Oil Company (DE)	El Paso CGP Company		51
	ANR Venture Eagle Point Company		49
Coastal Energy of Panama, Inc. (Panama)	Coastal Stock Company Limited		100
Coastal Energy Resources Ltd. (Mauritius)	Coastal India Petroleum Ltd.		100
Coastal Europe Limited (England)	Coastal Stock Company Limited		100
Coastal Finance I (DE)	El Paso CGP Company		100
Coastal Fuels of Puerto Rico, Inc. (DE)	Cosbel Petroleum Corporation		100
Coastal Fuji Oil Ltd. (Cayman Islands)	Coastal Petroleum N.V.		50
	Unaffiliated Parties		50
Coastal Gas Australia Pty Ltd. (Australia)	Coastal Gas International Ltd.		100
Coastal Gas de Mexico S de R.L. de C.V. (Mexico)	Coastal Halcon Pipeline I Ltd.		50
	Coastal Halcon Pipeline II Ltd.		50
Coastal Gas India Holdings Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Gas International Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Gas Storage Victoria Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Gas Storage Victoria Pty Ltd. (Australia)	Coastal Gas Storage Victoria Ltd.		100
Coastal Gusu Heat & Power Ltd. (Cayman Islands)	Coastal Suzhou Investor Ltd.		99
	Coastal Suzhou Manager Ltd.		1
Coastal Halcon Pipeline I Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Halcon Pipeline II Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Henan I Power Ltd. (Cayman Islands)	Coastal Henan Power Ltd.		100
Coastal Henan II Power Ltd. (Cayman Islands)	Coastal Henan Power Ltd.		100
Coastal Henan Power Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal India Petroleum Ltd. (Cayman Islands)	Coscol Petroleum Corporation		100

Page 3

		%
ENTITY NAME	OWNER	OWNERSHIP
Coastal Indonesia Bangko Ltd. (Cayman Islands)	El Paso Production Oil & Gas Company		100
Coastal International Finance Ltd. (Cayman Islands)	El Paso CNG Company, L.L.C.		100
Coastal Itabo, Ltd. (Cayman Islands)	Coastal Power Dominicana Generation Ltd.		100
Coastal Liquids Partners, L.P. (DE)	El Paso Merchant Energy-Petroleum Company (GP)		.804
	El Paso Merchant Energy-Petroleum Company (LP)		97.002
	El Paso Production Oil & Gas Company (LP)		2.194
Coastal Management Services (Singapore) Pte Ltd. (Singapore)	Coastal Securities Company Limited		100
Coastal Manager Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Mart, Inc. (DE)	El Paso Remediation Company		100
Coastal Mexicana Northeast Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Mexicana Northwest Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Mobile Refining Company (DE)	El Paso CGP Company		100
Coastal Nanjing Investor Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Nanjing Manager Ltd. (Cayman Islands)	Coastal Nanjing Investor Ltd.		100
Coastal Nanjing Power Ltd. (Cayman Islands)	Coastal Nanjing Investor Ltd.		99
	Coastal Nanjing Manager Ltd.		1
Coastal Nejapa Ltd. (Cayman Islands)	Coastal Salvadoran Power Ltd.		87
	Unaffiliated Parties		13
Coastal Offshore Finance Ltd. (Cayman Islands)	Coastal International Finance Ltd.		100
Coastal Offshore Fuels, Inc. (Liberia)	Cosbel Petroleum Corporation		100
Coastal Offshore Insurance Ltd. (Bermuda)	Coastal Offshore Finance Ltd.		100
Coastal Oil & Gas Australia 20 Pty Ltd. (Australia)	Coastal Australia AC 96-3 Ltd.		100
Coastal Oil & Gas Australia 21 Pty Ltd. (Australia)	Coastal Australia AC 96-4 Ltd.		100
Coastal Oil & Gas Australia 283 Pty Ltd. (Australia)	Coastal Development III Ltd.		100
Coastal Oil & Gas Australia Pty Ltd (Australia)	Coastal Development II Ltd.		100
Coastal Oil & Gas Camisea Ltd. (Cayman Islands)	El Paso Production Oil & Gas Company		100
Coastal Oil New England, Inc. (MA)	Cosbel Petroleum Corporation		100
Coastal Oil New York, Inc. (DE)	Cosbel Petroleum Corporation		100
Coastal Palembang Power (Singapore) Pte Ltd. (Singapore)	Coastal Palembang Power Ltd.		100
Coastal Palembang Power Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Peenya Investor Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Peenya Manager Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Peenya Power Ltd. (Mauritius)	Coastal Peenya Investor Ltd.		99
	Coastal Peenya Manager Ltd.		1
Coastal Petrochemical International (L) Limited (Labuan)	Coastal Petrochemical International A.V.V.		100
Coastal Petrochemical International A.V.V. (Aruba)	Coscol Petroleum Corporation		100
Coastal Petrochemical, Inc. (Quebec)	Cosbel Petroleum Corporation		51
	Unaffiliated Parties		49
Coastal Petrochemical, L.P. (Quebec)	Coastal Canada Petroleum, Inc. (LP)		50.999
	Coastal Petrochemical, Inc. (GP)		.002
	Unaffiliated Parties (LP)		48.999
Coastal Petroleum (Estonia) Ltd. (Cayman Islands)	Coscol Petroleum Corporation		100
Coastal Petroleum (Far East) Pte Ltd. (Singapore)	Coastal Securities Company Limited		100
Coastal Petroleum Argentina, S.A. (Argentina)	Coastal Petroleum N.V.		98
	Triunion Energy Company		2
Coastal Petroleum N.V. (Aruba)	Coastal Stock Company Limited		100
Coastal Petroleum N.V. Chile Limitada (Chile)	Coastal Petroleum N.V.		99.9
	Coastal India Petroleum Ltd.		.1
Coastal Pipeline Company (DE)	El Paso Merchant Energy-Petroleum Company		100
Coastal Power Central America Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Power Dominicana Generation Ltd.	El Paso CGP Company		2.072

Page 4

		%
ENTITY NAME	OWNER	OWNERSHIP
(Cayman Islands)	Coastal Power Guatemala Ltd.		97.928
Coastal Power Guatemala Distribution Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Power Guatemala Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Power India (Cayman) Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Power International II Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Power International III Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Power International IV Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Power International Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Power International V Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Power Lanka Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Power Nicaragua Holding Company Ltd. (Cayman Islands)	Coastal Power Nicaragua Ltd.		100
Coastal Power Nicaragua Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Power Noapara Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Power Panama Generation Ltd.	El Paso CGP Company		100
(Cayman Islands)
Coastal Power Panama Investor, S.A. (Panama)	Coastal Power Panama Generation Ltd.		100
Coastal Rajgarh Investor Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Romanian Petroleum International A.V.V. (Aruba)	Coastal Petroleum N.V.		49.5
	Unaffiliated Parties		50.5
Coastal Romanian Petroleum SRL (Romania)	Coscol Petroleum Corporation		49.5
	Unaffiliated Parties		50.5
Coastal Saba Investor II Ltd. (Cayman Islands)	Coastal Saba Investor Ltd.		99
	Coastal Saba Manager Ltd.		1
Coastal Saba Investor Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Saba Manager II Ltd. (Cayman Islands)	Coastal Saba Investor Ltd.		99
	Coastal Saba Manager Ltd.		1
Coastal Saba Manager Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Saba Power Ltd. (Mauritius)	Coastal Saba Investor II Ltd.		99
	Coastal Saba Manager II Ltd.		1
Coastal Salvadoran Power Ltd. (Cayman Islands)	Thermal Power Salvador Ltd.		100
Coastal Securities Company Limited (Bermuda)	Coastal Stock Company Limited		100
Coastal Services Petroleum (U.K.) Limited (England)	Coastal Europe Limited		100
Coastal States Energy Company (DE)	El Paso CGP Company		100
Coastal States Management Corporation (CO)	El Paso CGP Company		100
Coastal States Petroleum (U.K.) Limited (England)	Coastal Europe Limited		99.99
	Coastal States Tankers (U.K.) Limited		.01
Coastal States Tankers (U.K.) Limited (England)	Coastal Europe Limited		99.5
	Coastal States Petroleum (U.K.) Limited)		.5
Coastal States Trading Holdings Ltd. (Cayman Islands)	El Paso Merchant Energy-Petroleum Company		100
Coastal States Trading Investments Ltd.	El Paso Merchant Energy-Petroleum Company		100
(Cayman Islands)
Coastal Stock Company Limited (Bermuda)	Coscol Petroleum Corporation		57.37
	Coastal Austral Ltd.		.81
	Coastal Petrochemical International (L) Limited		19.22
	EPED B		16.34
	EnCap Holdings (Denmark) ApS		5.98
	El Paso Merchant Energy-Petroleum Company		.28
Coastal Subic Bay Terminal, Inc. (Philippines)	Coscol Petroleum Corporation		100
Coastal Suzhou Investor Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Suzhou Manager Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Suzhou Power Ltd. (Cayman Islands)	Coastal Suzhou Investor Ltd.		99

Page 5

		%
ENTITY NAME	OWNER	OWNERSHIP
	Coastal Suzhou Manager Ltd.		1
Coastal TDF Ltd. (Cayman Islands)	Coastal Cape Horn Ltd.		100
Coastal Technology Dominicana S.A.	El Paso Technology, Inc.		100	*
(Dominican Republic)
Coastal Technology Guatemala, Ltda.	Coastal States Trading Holdings Ltd.		50
(Guatemala LLC)	Coastal States Trading Investments Ltd.		50
Coastal Technology Ltd. (Cayman Islands)	El Paso Technology, Inc.		100
Coastal Technology Nicaragua S.A. (Nicaragua)	El Paso Technology, Inc.		100
Coastal Technology Palembang (Cayman) Ltd.	El Paso Technology, Inc.		100
(Cayman Islands)
Coastal Unilube, Inc. (TN)	El Paso CGP Company		100
Coastal Wartsila Petroleum Private Limited (India)	Coastal Energy Resources Ltd.		50
	Unaffiliated Parties		50
Coastal West Ventures, Inc. (DE)	El Paso CGP Company		100
Coastal Wuxi Investor Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Wuxi Manager Ltd. (Cayman Islands)	El Paso CGP Company		100
Coastal Wuxi New District Ltd. (Cayman Islands)	Coastal Wuxi Manager Ltd.		1
	Coastal Wuxi Investor Ltd.		99
Coastal Wuxi Power Ltd. (Cayman Islands)	Coastal Wuxi Manager Ltd.		99
	Coastal Wuxi Investor Ltd.		1
Colbourne Insurance Company Limited (England)	Coastal Europe Limited		77
	El Paso Energy Capital Company		23
Colorado Interstate Gas Company (DE)	El Paso Noric Investments III, L.L.C.		100
Colorado Water Supply Company (DE)	Colorado Interstate Gas Company		100
Compania de Electricidad de Puerto Plata, S.A. (Dominican Republic)	Coastal Power International Ltd.		47.79
	Coastal Technology Dominicana, S.A.		.01
	Coastal Salvadoran Power Ltd.		.01
	Coastal Wuxi Investor Ltd.		.01
	Coastal Wuxi Manager Ltd.		.01
	Unaffiliated Parties		52.17
Copper Eagle Gas Storage, LLC (DE)	El Paso Natural Gas Company		100
Cosbel Petroleum Corporation (DE)	El Paso CGP Company		100
Coscol Holding Company Ltd. (Cayman Islands)	Coscol Petroleum Corporation		100
Coscol Petroleum Corporation (DE)	El Paso CGP Company		100
Cross Country Development L.L.C. (DE)	El Paso Natural Gas Company		50.33
	Unaffiliated Parties		49.67
Crystal Exploration and Production, L.L.C. (DE)	Crystal Gas Storage, Inc.		100
Crystal Gas Storage, Inc. (DE)	El Paso Remediation Company		100
DBNGP Finance Company L.L.C. (DE)	EPED Holding Company		50
	Unaffiliated Parties		50
DeepTech International Inc. (DE)	El Paso Corporation		100
Diamond Power Holdings, L.L.C. (DE)	Diamond Power Ventures, L.L.C.		100
Diamond Power Ventures, L.L.C. (DE)	Garnet Power Holdings, L.L.C.		100
Distribuidora Coastal, S.A. de C.V. (El Salvador)	El Paso Merchant Energy-Petroleum Company		99
	Coastal States Management Corporation		1
Dover Technology, Inc. (TX)	DeepTech International Inc.		50
	Unaffiliated Parties		50
Ducto del Bajio, S. de R.L. de C.V. (Mexico)	Coastal Halcon Pipeline I Ltd.		50
	Coastal Halcon Pipeline II Ltd.		50
Duracom Mobile Power Corporation (Philippines)	East Asia Diesel Power Corporation		40
	Unaffiliated Parties		60
Dynaf Bolivia S.A. (Bolivia)	EPED Holding Company		100

Page 6

			%
ENTITY NAME	OWNER		OWNERSHIP
Eagle Point Cogeneration Partnership (General Partnership)(NJ)	Mesquite Investors, L.L.C. ANR Venture Eagle Point Company ANRV Eagle Point, L.P.	(GP) (GP) (GP)		16.34 ..17 83.49
East Asia Diesel Power Corporation (Philippines)	East Asia Power Resources Corporation			99.92
	Unaffiliated Parties			0.08
East Asia Global Management Ltd.	East Asia Power Resources Corporation			100
(British Virgin Islands)
East Asia Power Resources Corporation (Philippines)	EPHE Philippines Energy Company, Inc.			91.69	*
	El Paso Philippines Energy Company, Inc.			1.71
	Unaffiliated Parties			1.02
East Asia Power Services Inc. (Philippines)	East Asia Power Resources Corporation			100
East Asia Transmission and Distribution Corporation	East Asia Power Resources Corporation			100
(Philippines)
East Asia Utilities Corporation (Philippines)	El Paso Philippines Energy Company, Inc.			100
Eastern Insurance Company Limited (Bermuda)	El Paso Corporation			100
Eaton Rapids Gas Storage System (Joint Venture) (MI)	ANR Eaton Company			50
	Unaffiliated Parties			50
El Paso Marketing, L.P. (DE)	El Paso SPM Company	(LP)		23
	El Paso Merchant Energy Company	(GP)		1
	El Paso Merchant Energy-Gas Company	(LP)		76
El Paso (Labuan) Pty. Limited (Australia)	Cayger Finance Company			100
El Paso Amazonas Energia Ltda. (Brazil)	EPIC Energy Amazon Company			99.99
	El Paso Energy Rio Negro Company			0.01
El Paso ANR Investments, L.L.C. (DE)	American Natural Resources Company			100
El Paso ANRS Investments, L.L.C. (DE)	El Paso CGP Company			100
El Paso Asia (Labuan) Limited (Labuan)	EPED B Company			100
El Paso Bahamas Holding B.V. (Netherlands)	El Paso Pipeline Holding B.V.			100
El Paso Bastrop GP Company (DE)	El Paso CGP Company			100
El Paso Berkshire Power I Company, L.L.C. (DE)	Mesquite Investors, L.L.C.			100
El Paso Blue Atlantic US, Inc. (DE)	El Paso Corporation			100
El Paso Brazil Holdings Company (Cayman Islands)	El Paso Brazil, L.L.C.			100
El Paso Brazil, L.L.C. (DE)	El Paso Cayman BM-S-13 Company			12.96
	El Paso Cayman BS-1 Company			10.69
	El Paso Cayman BM-CAL-4 Company			10.05
	Unaffiliated Parties			40.21
	Small percentages owned by 11 other El Paso entities			26.09
El Paso Canada Pipeline B.V. (Netherlands)	El Paso Pipeline Holding B.V.			100
El Paso Canada Pipeline Company (Nova Scotia)	El Paso Canada Pipeline B.V.			100
El Paso Capital Investments, L.L.C. (DE)	El Paso Merchant Energy North America Company			100
El Paso Capital Trust II (DE)	El Paso Corporation			100
El Paso Capital Trust III (DE)	El Paso Corporation			100
El Paso Cayger III Company (Cayman Islands)	EPED B Company			100
El Paso Cayger IV Company (Cayman Islands)	El Paso Energy Cayger II Company			100
El Paso Cayman BAS-97 Company (Cayman Islands)	El Paso Production Oil & Gas Company (Ordinary Stock)			100
	El Paso Preferred Holdings Company (Preferred Stock)			100
El Paso Cayman BCAM-2 Company (Cayman Islands)	El Paso Production Oil & Gas Company (Ordinary Stock)			100
	El Paso Preferred Holdings Company (Preferred Stock)			100
El Paso Cayman BM-CAL-4 Company	El Paso Production Oil & Gas Company (Ordinary Stock)			100
(Cayman Islands)	El Paso Preferred Holdings Company (Preferred Stock)			100
El Paso Cayman BM-CAL-5 Company (Cayman Islands)	El Paso Production Oil & Gas Company (Ordinary Stock)			100
	El Paso Preferred Holdings Company (Preferred Stock)			100
El Paso Cayman BM-CAL-6 Company (Cayman Islands)	El Paso Production Oil & Gas Company (Ordinary Stock)			100
	El Paso Preferred Holdings Company (Preferred Stock)			100

Page 7

		%
ENTITY NAME	OWNER	OWNERSHIP
El Paso Cayman BM-ES-5 Company (Cayman Islands)	El Paso Production Oil & Gas Company (Ordinary Stock)		100
	El Paso Preferred Holdings Company (Preferred Stock)		100
El Paso Cayman BM-ES-6 Company (Cayman Islands)	El Paso Production Oil & Gas Company (Ordinary Stock)		100
	El Paso Preferred Holdings Company (Preferred Stock)		100
El Paso Cayman BM-PAMA-1 Company	El Paso Production Oil & Gas Company (Ordinary Stock)		100
(Cayman Islands)	El Paso Preferred Holdings Company (Preferred Stock)		100
El Paso Cayman BM-POT-11 Company	El Paso Production Oil & Gas Company (Ordinary Stock)		100
(Cayman Islands)	El Paso Preferred Holdings Company (Preferred Stock)		100
El Paso Cayman BM-POT-13 Company	El Paso Production Oil & Gas Company (Ordinary Stock)		100
(Cayman Islands)	El Paso Preferred Holdings Company (Preferred Stock)		100
El Paso Cayman BM-S-13 Company (Cayman Islands)	El Paso Production Oil & Gas Company (Ordinary Stock)		100
	El Paso Preferred Holdings Company (Preferred Stock)		100
El Paso Cayman BPAR-10 Company (Cayman Islands)	El Paso Production Oil & Gas Company (Ordinary Stock)		100
	El Paso Preferred Holdings Company (Preferred Stock)		100
El Paso Cayman Brazil Ventures Company	El Paso Production Oil & Gas Company (Ordinary Stock)		100
(Cayman Islands)	El Paso Preferred Holdings Company (Preferred Stock)		100
El Paso Cayman BS-1 Company (Cayman Islands)	El Paso Production Oil & Gas Company (Ordinary Stock)		100
	El Paso Preferred Holdings Company (Preferred Stock)		100
El Paso Cayman BT-PR-4 Company (Cayman Islands)	El Paso Production Oil & Gas Company (Ordinary Stock)		100
	El Paso Preferred Holdings Company (Preferred Stock)		100
El Paso Cayman CAL-M-312 (Cayman Islands)	El Paso Production Oil & Gas Company (Ordinary Stock)		100
	El Paso Preferred Holdings Company (Preferred Stock)		100
El Paso Cayman CAL-M-372 (Cayman Islands)	El Paso Production Oil & Gas Company (Ordinary Stock)		100
	El Paso Preferred Holdings Company (Preferred Stock)		100
El Paso Cayman DBNGP, Ltd. (Cayman Islands)	DBNGP Finance Company L.L.C.		100
El Paso Cayman TNG Company (Cayman Islands)	EPED B Company		100
El Paso CGP Company (DE)	El Paso Corporation		100
El Paso CGP Gas Transmission Company (DE)	El Paso Field Operations Company		100
El Paso Chaparral Holding Company (DE)	El Paso Tennessee Pipeline Co.		100
El Paso Chaparral Holding II Company (DE)	El Paso Chaparral Holding Company		100
El Paso Citrus Holdings, Inc. (DE)	Southern Natural Gas Company		100
El Paso CNG Company, L.L.C. (DE)	El Paso CGP Company		100
El Paso Coal Holding, L.L.C. (DE)	El Paso CGP Company		52.3
	American Natural Resources Company		47.7
El Paso Comercializadora de Energia Ltda. (Brazil)	El Paso Merchant Energy Americas do Sul (Cayman)		100	*
	Company
El Paso Compression Services de Mexico, S. de R.L. de C.V (Mexico)	. EPEC Nederland Holding B.V.		.0134
	El Paso Nederland Energie B.V.		99.9866
El Paso Construcoes Projetos e Consultoria Ltda. (Brazil)	El Paso Energy International do Brasil Ltda.		100	*
El Paso Corporate Foundation (TX)	El Paso Corporation		100
El Paso Dauphin Island Company, L.L.C. (DE)	El Paso Gas Gathering & Processing Company		99.9
	El Paso Field Operations Company		.1
El Paso DBNGP Limited (Labuan)	El Paso Cayman DBNGP, Ltd.		100
El Paso E & P International (Cayman Islands)	El Paso Production Oil & Gas Company		100
El Paso ECK Holding Company (DE)	EPED Holding Company		100
El Paso El Sauz B.V. (Netherlands)	EPEC Nederland Holding B.V.		100
El Paso Empreendimentos e Participacoes Ltda. (Brazil)	El Paso Energy Araucaria Company		100	*
El Paso Energia Cayman I Limited (Cayman Islands)	EPED Holding Company		100
El Paso Energia III Ltda. (Brazil)	El Paso Energy International do Brasil Ltda.		100	*
El Paso Energia Mexico, S. de R.L. de C.V. (Mexico)	El Paso Energy International Company		.002
	El Paso Latin America Inc		99.998
El Paso Energy Acajutla Company (Cayman Islands)	EPED B Company		100
El Paso Energy Amazon Company (Cayman Islands)	Amethyst Power Holdings, L.L.C.		100

Page 8

		%
ENTITY NAME	OWNER	OWNERSHIP
El Paso Energy Araucaria Company (Cayman Islands)	Aquamarine Power Holdings, L.L.C.		100
El Paso Energy Argentina Limitada S.A. (Argentina)	Triunion Energy Company		95
	Triunion Energy Inversiones Company		5
El Paso Energy Argentina Service Company (DE)	EPED Holding Company		100
El Paso Energy Asia Corporation (DE)	El Paso Energy International Company		100
El Paso Energy Bastrop LP, Inc. (DE)	El Paso CGP Company		100
El Paso Energy Brazil Corporation (Cayman Islands)	EPED B Company		100
El Paso Energy Bridge Holding Company, L.L.C. (DE)	El Paso Field Services Holding Company		100
El Paso Energy Capital Company (DE)	El Paso CGP Company		100
El Paso Energy Capital Trust I (DE)	El Paso Corporation		100
El Paso Energy Cayger II Company (Cayman Islands)	Aquamarine Power Holdings, L.L.C.		100
El Paso Energy E.S.T. Company (DE)	El Paso Corporation		100
El Paso Energy East Asia Company (Cayman Islands)	EPED B Company		100
El Paso Energy Engineering Company (DE)	El Paso Corporation		100
El Paso Energy Europe Limited (Scotland)	El Paso Energy Operating Services Company		100
El Paso Energy Gasoducto Company (Cayman Islands)	EPED B Company		100
El Paso Energy Global Holdings Company	EPED Holding Company		100
(Cayman Islands)
El Paso Energy Hydro Holding B.V. (Netherlands)	EPEC Nederland Holding B.V.		100
El Paso Energy India (Private) Ltd. (India)	El Paso International Power Operations Company		100
El Paso Energy International Company (DE)	El Paso Tennessee Pipeline Co.		100
El Paso Energy International do Brasil Ltda. (Brazil)	El Paso Energy Brazil Corporation		100	*
El Paso Energy Inversiones Central (Chile) Ltda. (Chile)	EPED Central Chile Corporation		99.9
	El Paso Latin America Inc.		.1
El Paso Energy Marketing de Mexico, S de RL de CV	El Paso Merchant Energy Company		96.67
(Mexico)	El Paso Nederland Energie B.V. (Note: El Paso Nederland Energie B.V. owns 100% of the Series B stock)		3.33
El Paso Energy Middle East Company (Cayman Islands)	EPED B Company		100
El Paso Energy Oil Transmission, L.L.C. (DE)	El Paso Production Oil & Gas Company		100
El Paso Energy Operating Services Company	EPED B Company		100
(Cayman Islands)
El Paso Energy Partners Company, L.L.C. (DE)	DeepTech International Inc.		100
El Paso Energy Pittsfield Corporation (DE)	El Paso Energy International Company		100
El Paso Energy Portland Corporation (DE)	Tennessee Gas Pipeline Company		100
El Paso Energy Portugal (Cayman) Company	EPED Holding Company		100
(Cayman Islands)
El Paso Energy Raton Corporation (DE)	El Paso Production Company		100
El Paso Energy Rio Negro Company (Cayman Islands)	El Paso Energy Amazon Company		100
El Paso Energy Service Company (DE)	El Paso Corporation		100
El Paso Energy Servicios S. de R.L. de C.V. (Mexico)	El Paso Energy International Company		1
	EPED Holding Company		99
El Paso Energy Singapore Pte. Ltd. (Singapore)	EPED B Company		100
El Paso EPN Investments, L.L.C. (DE)	El Paso San Juan Holding Company, L.P.		100
El Paso EPNG Investments, L.L.C. (DE)	El Paso Corporation		100
El Paso Europe Limited (Scotland)	El Paso Merchant Energy International Company		100
El Paso European Energie B.V. (Netherlands)	EPEC Nederland Holding B.V.		100
El Paso Field Operations Company (DE)	El Paso CGP Company		100
El Paso Field Services Holding Company (DE)	El Paso Tennessee Pipeline Co.		100
El Paso Field Services International Company	El Paso Tennessee Pipeline Co.		100
(Cayman Islands)
El Paso Field Services Management, Inc. (DE)	El Paso Field Services Holding Company		100
El Paso Field Services, L.P. (DE)	El Paso Field Services Management, Inc. (GP)		1
	El Paso Field Services Holding Company (LP)		99

Page 9

		%
ENTITY NAME	OWNER	OWNERSHIP
El Paso Fife I Company (Cayman Islands)	EPED B Company		100
El Paso Gas Gathering & Processing Company (DE)	El Paso Field Operations Company		100
El Paso Gas Liquids Marketing, L.L.C. (DE)	El Paso Field Operations Company		100
El Paso Gas Marketing Company (DE)	El Paso Merchant Energy-Gas Company		100
El Paso Gas Services Company (DE)	El Paso Corporation		100
El Paso Gas Transmission de Mexico, S. de R.L. de C.V.	El Paso Nederland Energie B.V.		96.6667
(Mexico)	EPEC Nederland Holding B.V.		3.3333
El Paso Global Gas (Bahamas) Limited (Bahamas)	El Paso LNG Holding II Company (issuance of shares		100
	pending)
El Paso Global Gas (Cayman) Company	El Paso Merchant Energy International Company		100
(Cayman Islands)
El Paso Global LNG Company (DE)	El Paso Tennessee Pipeline Co.		100
El Paso Global LNG Company, Ltd. (Bahamas)	El Paso LNG Holding II Company		100
El Paso Global Networks Company (DE)	El Paso Corporation		100
El Paso Great Lakes, Inc. (DE)	ANR Pipeline Company		100
El Paso Guna Power (Mauritius) Limited (Mauritius)	KLT Power (Asia)		100
El Paso Haripur Holding ApS (Denmark)	EPED A Company		100
El Paso Haripur Holding B.V. (Netherlands)	EPED A Company		100
El Paso Hungary Ltd. (Hungary)	El Paso Production Oil & Gas Company		99.8002
	El Paso Production Oil & Gas USA, L.P.		.1998
El Paso Indonesia B.V. (Netherlands)	EPEC Nederland Holding B.V.		100
El Paso Industrial Energy, L.P. (DE)	El Paso Merchant Energy Company (GP)		1
	El Paso Marketing, L.P.                    (LP)		99
El Paso International Power Operations Company (Cayman Islands)	El Paso Energy Global Holdings Company		100
El Paso Japan Holding B.V. (Netherlands)	EPEC Nederland Holding B.V.		100
El Paso Kabirwala Cayman Company (Cayman Islands)	El Paso Pakistan Power (Private) Limited		100
El Paso Kabirwala Power Ltd. (Cayman Islands)	El Paso Pakistan Power (Private) Limited		100
El Paso Khulna Power ApS (Denmark)	El Paso Power Khulna Holding Ltd.		100
El Paso Korea Holdings Limited (South Korea)	El Paso Asia (Labuan) Limited		99.67
	EPED B Company		.33
El Paso Latin America Inc. (DE)	El Paso Energy International Company		100
El Paso LNG Altamira B.V. (Netherlands)	El Paso LNG Holding B.V.		100
El Paso LNG Altamira II B.V. (Netherlands)	El Paso LNG Holding B.V.		100
El Paso LNG Baja B.V. (Netherlands)	El Paso LNG Holding B.V.		100
El Paso LNG Baja II B.V. (Netherlands)	El Paso LNG Holding B.V.		100
El Paso LNG Holding B.V. (Netherlands)	El Paso LNG Holding Company		100
El Paso LNG Holding Company (Cayman Islands)	El Paso Global LNG Company		100
El Paso LNG Holding II Company (Cayman Islands)	El Paso LNG Holding Company		100
El Paso LNG Luxembourg S.a.r.l. (Luxembourg)	El Paso LNG Holding Company		100
El Paso Marchwood Company (Cayman Islands)	EPED B Company		100
El Paso Mauritius Holding Limited (Mauritius)	EPED B Company		100
El Paso Mauritius Power Limited (Mauritius)	El Paso Energy International Company		100
El Paso Meizhou Wan Holding Company	EPED B Company		100
(Cayman Islands)
El Paso Merchant Energy Americas do Sul (Cayman) Company	El Paso Merchant Energy International Company		100
(Cayman Islands)
El Paso Merchant Energy Brazil, Ltd. (Cayman Islands)	El Paso Merchant Energy International Company		100
El Paso Merchant Energy Canada Inc. (Canada)	El Paso Marketing, L.P.		100
El Paso Merchant Energy Company (DE)	El Paso Merchant Energy North America Company		100
El Paso Merchant Energy do Brasil Ltda. (Brazil)	El Paso Merchant Energy Brazil, Ltd.		100	*
El Paso Merchant Energy Europe Holdings I Company (Cayman Islands)	El Paso Merchant Energy International Company		100

Page 10

		%
ENTITY NAME	OWNER	OWNERSHIP
El Paso Merchant Energy Europe Holdings II Company (Cayman Islands)	El Paso Merchant Energy International Company		100
El Paso Merchant Energy Europe Holdings III Company (Cayman Islands)	El Paso Merchant Energy International Company		100
El Paso Merchant Energy Europe Limited (UK)	El Paso Merchant Energy Europe Holdings I Company		100
El Paso Merchant Energy Europe Trading Limited (UK)	El Paso Merchant Energy Europe Holdings II Company		100
El Paso Merchant Energy International Company (Cayman Islands)	El Paso Energy Global Holdings Company		100
El Paso Merchant Energy North America Company (DE)	El Paso Tennessee Pipeline Co.		100
El Paso Merchant Energy Petroleum Limited (Scotland)	El Paso Merchant Energy Europe Holdings III Company		100
El Paso Merchant Energy-Gas Company (DE)	EPEC Corporation		100
El Paso Merchant Energy-Petroleum Company (DE)	El Paso CGP Company		100
El Paso Mexico Gasoductos B.V. (Netherlands)	EPEC Nederland Holding B.V.		100
El Paso Mexico Management B.V. (Netherlands)	EPEC Nederland Holding B.V.		100
El Paso Mexico Management S. de R.L. de C.V. (Mexico)	El Paso Mexico Management B.V.		99.99
	EPEC Nederland Holding B.V.		.01
El Paso Micogen Partner, Inc. (DE)	El Paso Midland, Inc.		100
El Paso Middle East B.V. (Netherlands)	El Paso Natural Gas Company		100
El Paso Midland, Inc. (DE)	El Paso CGP Company		100
El Paso Midwest Company (DE)	El Paso Energy Capital Company		100
El Paso Mojave Pipeline Co. (DE)	Sabine River Investors V, L.L.C.		100
El Paso Municipal Energy, L.L.C. (DE)	El Paso SPM Company		100
El Paso Natural Gas Company (DE)	El Paso EPNG Investments, L.L.C.		100
El Paso Nederland Energie B.V. (Netherlands)	EPEC Nederland Holding B.V.		100
El Paso Neuquen Holding Company (Cayman Islands)	El Paso Energy Argentina Service Company		100
El Paso Nicaragua Power Operations, S.A. (Nicaragua)	El Paso International Power Operations Company		99
	El Paso Energy Global Holdings Company		1
El Paso Noric Investments III, L.L.C. (DE)	El Paso CNG Company, L.L.C.		100
El Paso O&M do Brasil Ltda. (Brazil)	El Paso International Power Operations Company		99.9999
	El Paso Energy International do Brasil Ltda.		.0001
El Paso Offshore Supply Company (Cayman Islands)	EPED B Company		100
El Paso Oil & Gas Nova Scotia I, ULC (Nova Scotia)	El Paso Production Oil & Gas Company		100
El Paso Oleo e Gas do Brasil Ltda. (Brazil)	El Paso Brazil, L.L.C.		99.8002
	El Paso Brazil Holdings Company		.1998
El Paso Pakistan Power (Private) Limited (Pakistan)	El Paso Mauritius Power Limited		100	*
El Paso Panama Management S. de R.L. (Panama)	El Paso International Power Operations Company		95
	Coastal Power Panama Investor S.A.		5
El Paso Petroleum Marketing do Brasil Ltda. (Brazil)	El Paso Energy International do Brasil Ltda.		100	*
El Paso Petroleum Overseas N.V. (Aruba)	Coastal Stock Company Limited		100
El Paso Philippines Energy Company, Inc. (Philippines)	EPEC Nederland Holding B.V.		100	*
El Paso Pipeline Holding B.V. (Netherlands)	El Paso Corporation		100
El Paso Pipeline Services Company (DE)	El Paso Natural Gas Company		100
El Paso Power Khulna Holding Ltd. (Cayman Islands)	El Paso CGP Company		100
El Paso Power Operations Company (DE)	El Paso Merchant Energy North America Company		100
El Paso Power Purchasing, L.P. (DE)	El Paso Merchant Energy Company    (GP)		1
	El Paso SPM Company                        (LP)		99
El Paso PPC Holding B.V. (Netherlands)	EPEC Nederland Holding B.V.		100
El Paso PPN (Cayman) Company (Cayman Islands)	El Paso Corporation		100
El Paso Preferred Holdings Company (DE)	El Paso Production Oil & Gas Company		100
El Paso Production Company (DE)	El Paso Production Holding Company		100
El Paso Production Company Turkey BV (Netherlands)	El Paso Production Holdings BV		100

Page 11

		%
ENTITY NAME	OWNER	OWNERSHIP
El Paso Production GOM Inc. (DE)	El Paso Production Holding Company		100
El Paso Production Holding Company (DE)	El Paso Corporation		100
El Paso Production Holdings BV (Netherlands)	El Paso Corporation		100
El Paso Production International Cayman Company (Cayman Islands)	El Paso Corporation		100
El Paso Production Oil & Gas Company (DE)	El Paso CGP Company		100
El Paso Production Oil & Gas Gathering, L.P. (DE)	El Paso Production Oil & Gas Company (GP)		1
	El Paso Production Oil & Gas Holdings, Inc. (LP)		99
El Paso Production Oil & Gas Holdings, Inc. (DE)	El Paso Production Oil & Gas Company		100
El Paso Production Oil & Gas USA, L.P. (DE)	El Paso Production Oil & Gas Company (GP)		1
	El Paso Production Oil & Gas Holdings, Inc. (LP)		99
El Paso Production Oil and Gas Processing Canada, Inc. (New Brunswick)	El Paso Production Oil & Gas Company		100
El Paso Production Resale Company (DE)	El Paso Production Oil & Gas Company		100
El Paso Production Service Company (DE)	El Paso CGP Company		100
El Paso Reata Energy, L.P. (DE)	El Paso Merchant Energy Company (GP)		1
	El Paso Marketing, L.P. (LP)		99
El Paso Remediation Company (DE)	El Paso Corporation		100
El Paso Rio Bravo B.V. (Netherlands)	EPEC Nederland Holding B.V.		100
El Paso Rio Claro Ltda. (Brazil)	El Paso Energy Cayger II Company		99.99
	El Paso Cayger IV Company		0.01
El Paso Rio Grande Ltda. (Brazil)	El Paso Cayger III Company		100*
El Paso Rio Negro Energia Ltda. (Brazil)	El Paso Energy Rio Negro Company		99.99
	EPIC Energy Amazon Company		0.01
El Paso Rondonia Power Company (Cayman Islands)	Aquamarine Power Holdings, L.L.C.		100
El Paso Rosarito Company, L.L.C. (DE)	EPED Holding Company		100
El Paso Samalayuca Holding (Cayman) Company (Cayman Islands)	EPED SAM Holdings Company		100
El Paso San Juan Holding Company, L.P. (DE)	El Paso Field Services Management, Inc. (GP)		1
	El Paso Field Services Holding Company (LP)		99
El Paso Services (D.C.) Inc. (DE)	El Paso Energy Service Company		100
El Paso Services Holding Company (DE)	El Paso Tennessee Pipeline Co.		100
El Paso Shipping Holding Company (DE)	El Paso Energy Bridge Holding Company, L.L.C.		100
El Paso Sierra Chaco I Company (Cayman Islands)	EPED B Company		100
El Paso SLOC Holding Company (Cayman Islands)	Coscol Petroleum Corporation		100
El Paso Southern Pipeline Company (DE)	El Paso CGP Company		100
El Paso SPM Company (DE)	El Paso Merchant Energy Company		100
El Paso Tankships Malta, Ltd. (Malta)	El Paso SLOC Holding Company		99
	Coscol Holding Company Ltd.		1
El Paso Tankships USA Company (DE)	Coscol Petroleum Corporation		100
El Paso Technology El Salvador, S.A. de C.V.	El Paso Technology, Inc.		99
(El Salvador)	El Paso Energy Service Company		1
El Paso Technology Pakistan (Pvt.) Ltd. (Pakistan)	El Paso Technology, Inc.		100
El Paso Technology, Inc. (DE)	El Paso CGP Company		100
El Paso Telecom, L.L.C. (DE)	El Paso Global Networks Company		100
El Paso Tennessee Pipeline Co. (DE)	El Paso Corporation		100
	Unaffiliated Parties-Series A Preferred Stock		100
El Paso TGPC Investments, L.L.C. (DE)	El Paso Tennessee Pipeline Co.		100
El Paso Transmission Company (DE)	El Paso Corporation		100
El Paso WIC Investments, L.L.C. (DE)	El Paso CNG Company, L.L.C.		100
El Salvador Distribution Holding Company Ltd. (Cayman Islands)	Thermal Power Salvador Ltd.		100
Elba Marine Services, L.L.C. (DE)	Southern Natural Gas Company		100

Page 12

		%
ENTITY NAME	OWNER	OWNERSHIP
ELUSA Power II Investment, Ltd. (Cayman Islands)	Coastal Power International IV Ltd.		100
ELUSA Power Investment, Ltd. (Cayman Islands)	Coastal Power International IV Ltd.		100
EMA Power Kft. (Hungary)	Epic Energy Hungary B.V.		50
	Unaffiliated Parties		50
Emerald Finance, L.L.C. (DE)	El Paso Energia Cayman I Limited		100
Empresa de Generacion Electrica Fortuna, S.A. (Panama)	Americas Generation Corp.		49
	Unaffiliated Parties		51
Empresa Energetica Sierra Chaco S.A. (Bolivia)	EPED Holding Company		100
Empresa Generadora de Electricidad Itabo, S.A.	Coastal Itabo Ltd.		50*
(Dominican Republic)	Unaffiliated Parties		50
EnCap Holdings (Cayman) Company (Cayman Islands)	El Paso Merchant Energy International Company		100
EnCap Holdings (Denmark) ApS (Denmark)	Encap Holdings (Cayman) Company		100
EnCap Investments L.L.C. (DE)	El Paso Merchant Energy North America Company		33.3333
	Unaffiliated Parties		66.6666
Energia Coastal Guatemala S.A. (Guatemala)	Coastal Power International Ltd.		100
Energy Equity EPIC (Sengkang) Pty. Limited (Australia)	EPIC Sulawesi Gas Pty. Limited		50
	Unaffiliated Parties		50
Energy Maritime Holdings LLC (DE)	El Paso Tankships USA Company		50
	Unaffiliated Parties		50
Energy Maritime LLC (DE)	Energy Maritime Holdings LLC		100
Enfield Energy Centre Limited (United Kingdom)	Enfield Holdings BV		50
	Unaffiliated Parties		50
Enfield Holdings B.V. (Netherlands)	EPIC Energy Hungary B.V.		50
	Unaffiliated Parties		50
Enfield Operations (UK) Limited (United Kingdom)	Enfield Operations L.L.C.		100
Enfield Operations L.L.C. (DE)	Enfield Energy Centre Limited		51
	Unaffiliated Parties		49
Enterprise Products GP, LLC (DE)	GulfTerra GP Holding Company		9.9
	Unaffiliated Parties		90.1
EP Connect, L.L.C. (DE)	El Paso Global Networks Company		100
EP Power Finance, L.L.C. (DE)	El Paso Merchant Energy North America Company		100
EPEC Argentina Corporation (DE)	El Paso Energy International Company		100
EPEC Baja California Corporation (DE)	El Paso Energy International Company		100
EPEC Canada Ltd. (Canada)	El Paso Energy International Company		100
EPEC Cayman Islands Company (Cayman Islands)	EPED Holding Company		100
EPEC China Inc. (DE)	El Paso Energy International Company		100
EPEC Communications Corporation (DE)	Tennessee Gas Pipeline Company		100
EPEC Corporation (DE)	El Paso Services Holding Company		100
EPEC Ethanol Company (DE)	El Paso Energy International Company		100
EPEC Ethanol Services Company (DE)	El Paso Energy International Company		100
EPEC Europe Company (DE)	El Paso Energy International Company		100
EPEC Gas Brazil Corporation (DE)	El Paso Energy International Company		100
EPEC Gas Canada Ltd. (Ontario)	El Paso Energy International Company		100
EPEC Gas Chile Corporation (DE)	El Paso Energy International Company		100
EPEC Gas Services (Chile) Corporation (DE)	El Paso Energy International Company		100
EPEC Gas Transportes S.A. (Chile)	EPEC Gas Services (Chile) Corporation		100
EPEC Hungary Inc. (DE)	El Paso Energy International Company		100
EPEC International (East Asia/Pacific) Inc. (DE)	El Paso Energy International Company		100
EPEC Nederland B.V. (Netherlands)	El Paso Corporation		100
EPEC Nederland Holding B.V. (Netherlands)	EPED Holding Company		100
EPEC Polymers, Inc. (DE)	El Paso Remediation Company		100
EPEC Realty, Inc. (DE)	Tennessee Gas Pipeline Company		100
EPEC Ventures Bolivia Corporation (DE)	El Paso Energy International Company		100

Page 13

		%
ENTITY NAME	OWNER	OWNERSHIP
EPEC Ventures Poland Corporation (DE)	El Paso Energy International Company		100
EPEC West, Inc. (DE)	Tennessee Gas Pipeline Company		100
EPED A Company (Cayman Islands)	EPED Holding Company		100
EPED Aguaytia Company (Cayman Islands)	EPED A Company		99
	EPED B Company		1
EPED B Company (Cayman Islands)	EPED Holding Company		100
EPED Central Chile Corporation (DE)	EPED Holding Company		100
EPED Holding Company (DE)	El Paso Energy International Company		100
EPED SAM Holdings Company (DE)	EPED Holding Company		100
EPHE Philippines Energy Company, Inc. (Philippines)	El Paso Philippines Energy Company, Inc.		100*
EPIC Aguaytia Maple Company (Cayman Islands)	EPED A Company		99
	EPED B Company		1
EPIC Development (TPA) Pty. Ltd. (Australia)	EPED Holding Company		33.3
	Unaffiliated Parties		66.7
EPIC Energy (Australia) Nominees Pty. Ltd. (Australia)	El Paso DBNGP Limited		33.33*
	CNG Labuan One		33.33
	Unaffiliated Parties		33.34
	Acts as Trustee for EPIC Energy Australia Trust
EPIC Energy (Victoria) Investments Pty. Ltd. (Australia)	EPIC Energy (WA) Investments Pty. Ltd.		100
EPIC Energy (Victoria) Nominees Pty. Ltd. (Australia)	EPIC Energy (Australia) Nominees Pty. Ltd.		100
EPIC Energy (Victoria) Pipeline Trust (Australia)	EPIC Energy Australia Trust		100
	(EPIC Energy (Victoria) Nominees Pty Ltd. acts as
	Trustee)
EPIC Energy (Victoria) Transmission Pty. Ltd. (Australia)	EPIC Energy (WA) Investments Pty. Ltd.		100
EPIC Energy (WA) Investments Pty. Ltd. (Australia)	EPIC Energy Australia Trust		100
EPIC Energy (WA) Two Pty. Ltd. (Australia)	EPIC Energy (WA) Investments Pty. Ltd.		100
EPIC Energy Amazon Company (Cayman Islands)	Amethyst Power Holdings, L.L.C.		100
EPIC Energy Australia Trust (Australia)	El Paso DBNGP Limited		33.3
	CNG Labuan One		33.3
	Unaffiliated Parties		33.4
	(EPIC Energy (Australia) Nominees Pty. Ltd. acts as
	trustee)
EPIC Energy Finance Pty. Ltd. (Australia)	EPIC Energy (WA) Investments Pty. Ltd.		100
EPIC Energy Hungary B.V. (Netherlands)	El Paso Energy International Company		100
EPIC Energy Western Australia Pty. Limited (Australia)	EPIC Energy (WA) Investments Pty. Ltd.		100
EPIC Gas International Servicos do Brasil Ltda. (Brazil)	EPEC Gas Brazil Corporation		84.83
	El Paso Services Holding Company		.01
	El Paso Energy International Company		15.16
EPIC Samalayuca A, L.L.C. (DE)	El Paso Samalayuca Holding (Cayman) Company		100
EPIC Sulawesi Gas Pty. Limited (Australia)	Ventures Holdings Pty. Limited		100
EPNG Mojave, Inc. (DE)	Sabine River Investors V, L.L.C.		100
Fauji Kabirwala Power Company Limited (Pakistan)	El Paso Kabirwala Power Ltd.		42.173*
	Unaffiliated Parties		57.827
Fife Power (Scotland)	El Paso Fife I Company		50
	Unaffiliated Parties		50
First Electric Utilities Services Corporation (Philippines)	East Asia Transmission and Distribution Corporation		100
Florida Gas Transmission Company (DE)	Citrus Corp.		100
Fort Union Gas Gathering, L.L.C. (DE)	CIG Resources Company		10.01
	Unaffiliated Parties		89.99
Fujian Electric (Hong Kong) LDC (Cayman Islands)	Meizhou Wan Generating Company, Ltd.		69.8
	Unaffiliated Parties		30.2
Fujian Pacific Electric Company LTD. (PRC WFOE) (Republic of China)	Fujian Electric (Hong Kong) LDC		100
Galtee Limited (Cayman Islands)	El Paso Energy International Company		100
Garnet Power Holdings, L.L.C. (DE)	EPED B Company		100

Page 14

		%
ENTITY NAME	OWNER	OWNERSHIP
Gas de Chile S.A. (Chile)	EPEC Gas Chile Corporation		50
	Unaffiliated Parties		50
Gas TransBoliviano S.A. (Bolivia)	EPED B Company		2
	Unaffiliated Parties		98
Gasoducto del Pacifico (Argentina) S.A. (Argentina)	El Paso Energy Argentina Limitada S.A.		12.5
	Gasoducto del Pacifico (Cayman) Ltd.		87.5
	Note: El Paso Energy Argentina Limitada S.A. owns 21.8% of the Preferred Stock; remaining percentage of the Preferred Stock is owned by unaffiliated parties.
Gasoducto del Pacifico (Cayman) Ltd. (Cayman Islands)	Triunion Energy Pacifico Company		21.8
	Unaffiliated Parties		78.2
Gasoducto del Pacifico (Chile) S.A. (Chile)	Gasoducto del Pacifico (Cayman) Ltd.		87.5
	Triunion Energy Inversiones (Chile) Limitada		12.5
	Note: Triunion Energy InversionesPacifico (chile) Limitada owns 21.8% of the Preferred Stock; remaining percentage of the Preferred Stock is owned by unaffiliated parties.
Gasoductos de Chihuahua, S. de R.L. de C.V. (Mexico)	El Paso Energy International Company		50
	Unaffiliated Parties		50
Gasoductos de Tamaulipas, S. de R.L. de C.V. (Mexico)	Gasoductos de Chihuahua S de RL de CV		99.99
	Gasoductos Servicios S de RL de CV		.01
Gasoductos Servicios, S. de R.L. de C.V. (Mexico)	Gasoductos de Chihuahua S de RL de CV		99.99
	Gasoductos de Tamaulipas S de RL de CV		.01
GEBF, L.L.C. (LA)	Vermilion Bay Land, L.L.C.		33.3333
	Unaffiliated Parties		66.6666
Gemstone Administracao Ltda. (Brazil)	EPED B Company		99.99
	El Paso Energy International do Brasil Ltda.		.01
Gemstone Investor Limited (Cayman Islands)	EPED Holding Company (Ordinary Class A)		100
	El Paso Corporation (Ordinary Class B)		100
Gemstone Investor, Inc. (DE)	Gemstone Investor Limited		100
Generadora Electrica Occidental S.A. (Nicaragua)	Coastal Power International IV, Ltd.		26
	Unaffiliated Parties		74
GLGT Aviation Company (DE)	Great Lakes Gas Transmission Limited Partnership		100
GLGT, Inc. (DE)	Great Lakes Gas Transmission Company		100
Great Lakes Gas Transmission Company (DE)	El Paso Great Lakes, Inc.		50
	Unaffiliated Parties		50
Great Lakes Gas Transmission Limited Partnership (DE)	El Paso Great Lakes, Inc.		45.69
	Great Lakes Gas Transmission Company		8.62
	Unaffiliated Parties		45.69
GulfTerra GP Holding Company (DE)	DeepTech International Inc.		100
GulfTerra Management, L.L.C. (DE)	El Paso Energy Partners Company, L.L.C.		100
Habibullah Coastal Power Company (Private) Limited	Quetta Power Holding Company I Ltd.		99
(Pakistan)	Quetta Power Holding Company II Ltd.		1
Harbortown Commercial Partnership (MI)	ANR Development Corporation		66.66
	Unaffiliated Parties		33.33
Harbortown Condominium Partnership (MI)	ANR Development Corporation		66.66
	Unaffiliated Parties		33.33
Harbortown Development Partnership (MI)	ANR Development Corporation		66.66
	Unaffiliated Parties		33.33
Harbortown Limited Dividend Housing Association (MI)	ANR Development Corporation		50
	Unaffiliated Parties		50
Holborn Oil Trading Limited (Bermuda)	Coastal Securities Company Limited		100
Hungary Power Holdings B.V. (Netherlands)	Epic Energy Hungary B.V.		100
Interenergy Company (Cayman Islands)	EPED B Company		100
Inversiones EPEC Gas (Chile) Limitada (Chile)	EPEC Gas Chile Corporation		99.99
	El Paso Latin America Inc.		.01
Jackson Pipeline Company (General Partnership) (MI)	ANR Jackson Company		25
	Unaffiliated Parties		75

Page 15

		%
		OWNER-
ENTITY NAME	OWNER	SHIP
Javelina Company (General Partnership) (TX)	El Paso Field Operations Company		40
	Unaffiliated Parties		60
Javelina Pipeline Company (General Partnership) (TX)	El Paso Field Operations Company		40
	Unaffiliated Parties		60
Jewel Investor, L.L.C. (DE)	EPED Holding Company		100
Key Ocean Services, Inc. (TX)	DeepTech International Inc.		50
	Unaffiliated Parties		50
Khulna Power Company Ltd. (Bangladesh)	El Paso Khulna Power ApS		73.9
	Unaffiliated Parties		26.1
KLT Power Asia (Cayman Islands)	KLT Power Inc.		100
KLT Power Inc. (MO)	EPED Holding Company		100
KLT Power Latin America (Cayman Islands)	KLT Power Inc.		100
Korea Independent Energy Corporation (Korea)	El Paso Korea Holdings Limited		50
	Unaffiliated Parties		50
Lakeside Purchaser, LLC (DE)	El Paso Global Networks Company		100
Latin America Capital L.L.C. (Cayman Islands)	EPED Aguaytia Company		27.5
	The Maple Gas Development Corporation		16.96
	Unaffiliated Parties		55.54
Limestone Electron, L.L.C. (DE)	El Paso Chaparral Holding Company El Paso Chaparral Holding II Company		13 87
MASSPOWER (MA)	MASSPOWER, L.L.C.		30
	MassPower Holdings I, L.L.C.		2.1
	MassPower Holdings II, L.L.C.		1.4
	Unaffiliated Parties		66.5
MassPower Holdings I, L.L.C. (DE)	Mesquite Investors, L.L.C.		100
MassPower Holdings II, L.L.C. (DE)	Mesquite Investors, L.L.C.		100
MassPower Holdings III, L.L.C. (DE)	Mesquite Investors, L.L.C.		100
MASSPOWER, L.L.C. (DE)	MassPower Holdings III, L.L.C.		2
	Unaffiliated Parties		98
McCoy Caney Coal Company (DE)	Coastal Coal, Inc.		100
MEI Limited Partnership (DE)	El Paso Midland, Inc. (LP)		49
	El Paso Midland, Inc. (GP)		1
	Source Midland Limited Partnership (LP)		49
	Source Midland Limited Partnership (GP)		1
Meizhou Wan Generating Company, Ltd.	El Paso Meizhou Wan Holding Company		35.53
(Cayman Islands)	Unaffiliated Parties		64.47
Mesquite Investors, L.L.C. (DE)	Chaparral Investors, L.L.C.		100
Mesquite Prime Holdings II, L.L.C. (DE)	Mesquite Investors, L.L.C.		100
Micogen Limited Partnership (DE)	El Paso Midland, Inc. (LP)		99
	El Paso Micogen Partner, Inc. (GP)		1
Mid Michigan Gas Storage Company (MI)	American Natural Resources Company		100
Midland Cogeneration Venture Expansion, LLC (DE)	El Paso Midland, Inc.		50
	Unaffiliated Parties		50
Midland Cogeneration Venture Limited Partnership (MI)	El Paso Midland, Inc.		10.875
	MEI Limited Partnership		4.985
	El Paso Micogen Partner, Inc.		.045
	Micogen Limited Partnership		4.486
	Source Midland Limited Partnership		18.125
	Alanna Corporation		.00001
	Unaffiliated Parties		61.484
Minnow Energy Pty Ltd (Australia)	El Paso DBNGP Limited		33.34
	Unaffiliated Parties		66.66
Mohawk River Funding II, L.L.C. (DE)	Mesquite Investors, L.L.C.		100

Page 16

		%
		OWNER-
ENTITY NAME	OWNER	SHIP
Mohawk River Funding III, L.L.C. (DE)	Mesquite Investors, L.L.C.		100
Mojave Pipeline Company (General Partnership) (TX)	El Paso Mojave Pipeline Co.		50
	EPNG Mojave, Inc.		50
Mojave Pipeline Operating Company (TX)	Mojave Pipeline Company		100
Mont Belvieu Land Company (DE)	El Paso Remediation Company		100
Mt. Franklin Insurance Ltd. (Bermuda)	El Paso Corporation		100
Nanjing Coastal Xingang Cogeneration Power Plant (China)	Coastal Nanjing Power Ltd.		80
	Unaffiliated Parties		20
Nejapa Power Company, L.L.C. (DE)	Coastal Nejapa Ltd.		.5
	Coastal Salvadoran Power Ltd.		.5
	Unaffiliated Parties		99
NEPC Consortium Power Ltd. (Bangladesh)	El Paso Haripur Holding ApS		50.001*
	Unaffiliated Parties		49.999
New Caribbean Investment, S.A. (Dominican Republic)	Coastal Itabo, Ltd.		49.97
	Coastal Power Dominicana Generation		.01
	Coastal Technology Dominicana S.A.		.01
	Unaffiliated Parties		50.01
Oil Casualty Insurance Ltd. (Bermuda)	El Paso Tennessee Pipeline Co.		8.14
	Unaffiliated Parties		91.86
Pacific Refining Company (General Partnership) (CA)	Coastal West Ventures, Inc. (GP)		99
	El Paso Merchant Energy-Petroleum Company (GP)		1
Palembang Coastal Technology (Singapore) Pte Ltd. (Singapore)	Coastal Technology Palembang (Cayman) Ltd.		100
Pawtucket Power Associates Limited Partnership (MA)	Pawtucket Power Holding Company, L.L.C. (LP)		99
	Pawtucket Power Generation, L.L.C. (GP)		1
Pawtucket Power Generation, L.L.C. (DE)	Pawtucket Power Holding Company, L.L.C.		100
Pawtucket Power Holding Company, L.L.C. (DE)	Mesquite Investors, L.L.C.		100
Pedregal Power Company S. de R.L. (Panama)	Coastal Power Panama Generation Ltd.		21.22
	Unaffiliated Parties		78.78
Peenya Power Company (India)	Coastal Peenya Power Ltd.		50
	Unaffiliated Parties		50
Peridot Finance S.a.r.l. (Luxembourg)	Diamond Power Holdings, L.L.C.		100
Peru Energy Holdings (Cayman Islands)	EPED Aguaytia Company		100
Peru Energy Holdings L.L.C. (DE)	Aguaytia Energy L.L.C.		99
	Peru Energy Holdings		1
Pescada Arabiana Exploracao e Producto de Petroleo e Gas	Potiguar II, L.L.C.		99.8
Ltda. (Brazil)	Potiguar 4A LLC		.1
	Unaffiliated Parties		.1
Plata Power, Ltd. (Cayman Islands)	Coastal Power International IV Ltd.		100
Polar Delta Project Ltd. (Canada)	EPEC Gas Canada Ltd.		50
	Unaffiliated Parties		50
Potiguar 4A LLC (DE)	Potiguar I, Ltd.		100
Potiguar 4B LLC (DE)	Potiguar I, Ltd.		100
Potiguar I, L.L.C. (DE)	El Paso Production International Cayman Company		100
Potiguar I, Ltd. (Mauritius)	El Paso Production International Cayman Company		100
Potiguar II, L.L.C. (DE)	Potiguar I, L.L.C.		100
PPN Mauritius Company (Mauritius)	El Paso PPN (Cayman) Company		100
PPN Power Generating Company Ltd. (India)	PPN Mauritius Company		26
	Unaffiliated Parties		74
PT Energi Sengkang (Indonesia)	Sulawesi Energy Pty. Limited		95
	Unaffiliated Parties		5
Quetta Power Holding Company I Ltd.	Coastal Power International II Ltd.		50
(Cayman Islands)	Unaffiliated Parties		50

Page 17

		%
		OWNER-
ENTITY NAME	OWNER	SHIP
Quetta Power Holding Company II Ltd. (Cayman Islands)	Quetta Power Holding Company I Ltd. Coastal Power International II Ltd.		98 1
	Unaffiliated Parties		1
Rensselaer Plant Holdco, L.L.C. (DE)	El Paso Merchant Energy-Petroleum Company		100
Rondonia Power Company (Cayman Islands)	El Paso Rondonia Power Company		50
	Unafilliated Parties		50
S.K. Petroleum Company (DE)	El Paso Energy International Company		100
Saba Power Company (Private) Limited (Pakistan)	Coastal Saba Power Ltd.		92.154*
	Unaffiliated Parties		7.846
Sabine River Investors I, L.L.C. (DE)	El Paso Energy Partners Company, L.L.C.		100
Sabine River Investors II, L.L.C. (DE)	El Paso Field Services Holding Company		100
Sabine River Investors III, L.L.C. (DE)	Tennessee Gas Pipeline Company		100
Sabine River Investors IV, L.L.C. (DE)	Southern Natural Gas Company		100
Sabine River Investors V, L.L.C. (DE)	El Paso Natural Gas Company		100
Samalayuca II Management, L.L.C. (DE)	EPED SAM Holdings Company		50
	Unaffiliated Parties		50
Samalayuca II Management, S. de R.L. de C.V. (Mexico)	Samalayuca II Management L.L.C.		98
	EPED SAM Holdings Company		1
	Unaffiliated Parties		1
San Joaquin Cogen, L.L.C. (DE)	Mesquite Investors, L.L.C.		100
Sandbar Petroleum Company (DE)	El Paso Energy International Company		100
Santiago Power, Ltd. (Cayman Islands)	Coastal Power International IV Ltd.		100
Seafarer Bahamas Pipeline System, Ltd. (Bahamas)	El Paso Energy International Company (issuance of shares pending)		100
Seafarer US Pipeline System, Inc. (DE)	El Paso Corporation		100
Source Midland Limited Partnership (DE)	El Paso Midland, Inc. (LP)		80
	El Paso Micogen Partner, Inc. (GP)		20
Southern Gas Storage Company (DE)	Sabine River Investors IV, L.L.C.		100
Southern LNG Inc. (DE)	Southern Natural Gas Company		100
Southern Natural Gas Company (DE)	El Paso Corporation		100
Starr-Zapata Pipe Line (General Partnership) (TX)	El Paso CGP Gas Transmission Company		50
	Unaffiliated Parties		50
Subic Bay Petroleum Products Ltd. (Cayman Islands)	Coastal Stock Company Limited		100
Sulawesi Energy Pty Limited (Australia)	Ventures Holdings Pty. Limited		50
	Unaffiliated Parties		50
Sunrise Power Company Inc. (Philippines)	East Asia Diesel Power Corporation		66.67
	Unaffiliated Parties		33.33
Suzhou Coastal Cogeneration Power Co., Ltd. (China)	Coastal Suzhou Power Ltd.		60
	Unaffiliated Parties		40
Suzhou New District Cogeneration Company (China)	Coastal Suzhou Power Ltd.		60
	Unaffiliated Parties		40
Suzhou Suda Cogeneration Power Company Ltd. (China)	Coastal Gusu Heat & Power, Ltd.		60
	Unaffiliated Parties		40
TCN Energia Ltda. (Brazil)	EPED B Company		100*
TDF, S. de R.L. de C.V. (Mexico)	Transportadora del Norte SH, S. de R.L. de C.V.		99.99999
	Gasoductos Servicios, S. de R.L. de C.V.		.00001
Teco Gas Gathering LLC (DE)	El Paso Field Services, L.P.		100
Teco Gas Processing LLC (DE)	El Paso Field Services Holding Company		100
Tennessee Gas Pipeline Company (DE)	El Paso TGPC Investments, L.L.C.		100
Tennessee Storage Company (DE)	Sabine River Investors III, L.L.C.		100
Termo Norte Energia Ltda. (Brazil)	Rondonia Power Company		99.99981
	El Paso Energy International do Brasil Ltda.		0.00009
	Unaffiliated Parties		0.00009

Page 18

		%
		OWNER-
ENTITY NAME	OWNER	SHIP
The Maple Gas Development Corporation	Epic Aguaytia Maple Company		13.1
(Cayman Islands)	Unaffiliated Parties		86.9
Thermal Power Salvador Ltd. (Cayman Islands)	El Paso CGP Company		100
Tipitapa Power Company Ltd. (Cayman Islands)	Coastal Power Nicaragua Ltd.		59
	Coastal Power Nicaragua Holding Company Ltd.		1
	Unaffiliated Parties		40
Topaz Power Ventures, L.L.C. (DE)	EPED Holding Company		100
Transport USA, Inc. (PA)	ANR Advance Holdings, Inc.		100
Transportadora Brasiliera Gasoducto Bolivia-Brazil S.A. (Brazil)	BBPP Holdings Ltda. Unaffiliated Parties		25 75
Transportadora del Norte SH, S. de R.L. de C.V. (Mexico)	Gasoductos de Chihuahua S. de R.L. de C.V.		99.99999
	Gasoductos Servicios, S. de R.L. de C.V.		.00001
Triangle Finance Company, LLC (DE)	Coastal Power Guatemala Ltd.		46
	Unaffiliated Parties		54
Triunion Energy Chile A Company (Cayman Islands)	Triunion Energy Inversiones Company		100
Triunion Energy Company (Cayman Islands)	Agua del Cajon (Cayman) Company		38.4
	Interenergy Company		38.4
	EPED B Company		23.2
Triunion Energy Finance Pacifico Company (Cayman Islands)	Triunion Energy Inversiones Company		100
Triunion Energy Inversiones (Chile) Limitada (Chile)	Triunion Energy Chile A Company		0.1
	Triunion Energy Pacifico Company		99.9
Triunion Energy Inversiones Company (Cayman Islands)	Triunion Energy Company		100
Triunion Energy Inversiones Pacifico (Chile) Limitada	Triunion Energy Pacifico Company		0.1
(Chile)	Triunion Energy Inversiones (Chile) Limitada		99.9
Triunion Energy Pacifico Company (Cayman Islands)	Triunion Energy Inversiones Company		100
U.E.G. Araucaria Ltda. (Brazil)	El Paso Empreendimentos e Participacoes Ltda.		60
	Unaffiliated Parties		40
United Summit Coastal Oil Ltd. (Bangladesh)	Coastal Petroleum N.V.		50
	Unaffiliated Parties		50
UnoPaso Exploracao e Producao de Petroleo e Gas Ltda.	Potiguar II, L.L.C.		99.8
(Brazil)	Potiguar 4B LLC		.1
	Unaffiliated Parties		.1
VEN Energy Holding Company (Cayman Islands)	EPED B Company		100
VEN Field Services Company (Cayman Islands)	EPED B Company		100
Ventures Holdings Pty. Limited (Australia)	Galtee Limited		100
Vermilion Bay Land, L.L.C. (DE)	Crystal Gas Storage, Inc.		100
Wasatch Wax L.L.C. (DE)	El Paso Merchant Energy-Petroleum Company		33.33
	Unaffiliated Parties		66.66
Western Fuel Oil Company (CA)	Pacific Refining Company (General Partnership)		100
Wielkopolska Energia S.A. (Poland)	EPEC Ventures Poland Corporation		50
	Unaffiliated Parties		50
Wuxi Huada Gas Turbine Electric Power Company (China)	Coastal Wuxi Power Ltd.		60
	Unaffiliated Parties		40
Wyco Development LLC	CIG Gas Supply Company		50
	Unaffiliated Parties		50
Wyoming Gas Supply Inc. (DE)	El Paso WIC Investments, L.L.C.		100
Wyoming Interstate Company Ltd. (CO)	Wyoming Gas Supply Inc. (LP)		50
	CIG Gas Supply Company (GP)		50
Young Gas Storage Company, Ltd. (CO)	CIG Gas Storage Company		47.5
	Unaffiliated Parties		52.5

Page 19

		%
		OWNER-
ENTITY NAME	OWNER	SHIP
Zipline, L.L.C. (DE)	El Paso Global Networks Company		50
	Unaffiliated Parties		50

* A very small percentage of stock was issued to Officers/Directors pursuant to the requirements of corporate laws in that country.

Page 20

EX-23.A

EXHIBIT 23.A

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (File No. 333-82412) and Form S-8 (File Nos. 333-96959, 333-26813, 333-26831, 333-26823, 033-46519, 033-49956, 033-51851, 033-57553, 033-51853, 333-75781, 333-78949, 333-78951, 333-78979, 333-94717, 333-94719, 333-52100, 333-64240, 333-64236, 333-31060, 333-82506) of El Paso Corporation of our report dated March 25, 2005 relating to the consolidated financial statements and financial statement schedule, management’s assessment of the effectiveness of internal control over financial reporting and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 25, 2005

  EX-23.B 17 h22162exv23wb.htm CONSENT OF PRICEWATERHOUSECOOPERS LLP (DETROIT)

EXHIBIT 23.B

Consent of Independent Registered Public Accounting Firm

We hereby consent to the incorporation by reference in the Registration Statements on Forms S-8 (Nos. 333-96959, 333-26813, 333-26831, 333-26823, 33-46519, 33-49956, 33-51851, 33-57553, 33-51853, 333-75781, 333-78949, 333-78951, 333-78979, 333-94717, 333-94719, 333-52100, 333-64240, 333-64236, 333-31060, 333-82506) and S-3 (No. 333-82412) of El Paso Corporation of our report dated February 25, 2005 relating to the financial statemetns, management’s assessment of the effectiveness of internal control over financial reporting and the effectiveness of internal control over financial reporting of Midland Cogeneration Venture L.P. which appears in the El Paso Corporation Form 10-K for the year ended December 31, 2004.

/s/ PricewaterhouseCoopers LLP

Detroit, Michigan

March 22, 2005

EX-23.B

exv23wb

EX-23.C

(RYDER SCOTT COMPANY LETTERHEAD)

Exhibit 23.C

CONSENT OF RYDER SCOTT COMPANY, L.P.

     As independent petroleum engineers, Ryder Scott Company, L.P. hereby consents to the incorporation by reference in the Registration Statements on Form S-3 (File No. 333-82412) and Form S-8 (File Nos. 333-96959, 333-26813, 333-26831, 333-26823, 033-46519, 033-49956, 033-51851, 033-57553, 033-51853, 333-75781, 333-78949, 333-78951, 333-78979, 333-94717, 333-94719, 333-52100, 333-64240, 333-64236, 333-31060, 333-82506) of El Paso Corporation of the reference to us and our report under the captions “Part I, Item 1. — Business, Non-regulated Businesses — Production Segment — Natural Gas, Oil and Condensate and Natural Gas Liquids Reserves”, “Part II, Item 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations, Individual Segment Results, Non-regulated Businesses — Production Segment — Reserves Production and Costs” and “Part II, Item 8. — Financial Statements and Supplementary Data, Note 26. — Supplemental Natural Gas and Oil Operations (Unaudited)” appearing in the Annual Report on Form 10-K of El Paso Corporation for the year ended December 31, 2004.

/s/ Ryder Scott Company, L.P.  

Ryder Scott Company, L.P. 

Houston, Texas
March 24, 2005

1200, 530-8TH AVENUE, S.W.	CALGARY, ALBERTA T2P 3S8	TEL (403) 262-2799	FAX (403) 262-2790
621 17TH STREET, SUITE 1550	DENVER, COLORADO 80293-1501	TEL (303) 623-9147	FAX (303) 623-4258

EX-31.A

EXHIBIT 31.A

CERTIFICATION

I, Douglas L. Foshee, certify that:

1. I have reviewed this Annual Report on Form 10-K of El Paso Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 25, 2005

/s/ Douglas L. Foshee

Douglas L. Foshee

President and Chief Executive Officer

(Principal Executive Officer)

El Paso Corporation

EX-31.B

EXHIBIT 31.B

CERTIFICATION

I, D. Dwight Scott, certify that:

1. I have reviewed this Annual Report on Form 10-K of El Paso Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 25, 2005

/s/ D. Dwight Scott

D. Dwight Scott

Executive Vice President and Chief Financial Officer

(Principal Financial Officer)

El Paso Corporation

EX-32.A

EXHIBIT 32.A

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

      In connection with the Annual Report on Form 10-K for the period ending December 31, 2004, of El Paso Corporation (the “Company”) as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Douglas L. Foshee, President and Chief Executive Officer, certify (i) that the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Douglas L. Foshee

Douglas L. Foshee

President and Chief Executive Officer

(Principal Executive Officer)

March 25, 2005

A signed original of this written statement required by Section 906 has been provided to El Paso Corporation and will be retained by El Paso Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.B

EXHIBIT 32.B

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

      In connection with the Annual Report on Form 10-K for the period ending December 31, 2004, of El Paso Corporation (the “Company”) as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, D. Dwight Scott, Executive Vice President and Chief Financial Officer, certify (i) that the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ D. Dwight Scott

D. Dwight Scott

Executive Vice President and

Chief Financial Officer

(Principal Financial Officer)

March 25, 2005

A signed original of this written statement required by Section 906 has been provided to El Paso Corporation and will be retained by El Paso Corporation and furnished to the Securities and Exchange Commission or its staff upon request.