Edgar Filing: EL PASO CORP/DE

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the

Securities Exchange Act of 1934

Date of Report:

May 12, 2006

(Date of Earliest Event Reported: March 31, 2006)

EL PASO CORPORATION

(Exact name of Registrant as specified in its charter)


Delaware	1-14365	76-0568816
(State or other jurisdiction of incorporation or organization)	(Commission File Number)	(I.R.S. Employer Identification No.)

El Paso Building

1001 Louisiana Street

Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code (713) 420-2600

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:


o	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 8.01, Other Events.

In March 2006, our Board of Directors approved the sale of our interest in Macae, a wholly owned power plant in Brazil, to Petrobras. We reported Macae as discontinued operations in our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2006. On April 27, 2006, we completed the sale. See our Current Report on Form 8-K dated May 3, 2006.

This Current Report on Form 8-K was prepared to provide revised financial information and a discussion of our business that presents Macae as discontinued operations for all periods presented in our Annual Report on Form 10-K for the year ended December 31, 2005, filed on March 7, 2006. It should be noted that our net income was not impacted by the reclassification of Macae to discontinued operations. We have not otherwise updated our financial information or business discussion for activities or events occurring after the date this information was presented in our 2005 Form 10-K. You should read our Quarterly Report on Form 10-Q for the period ended March 31, 2006, for updating information.

This filing includes updated information for the following items included in our 2005 Form 10-K:


	Page

Item 1, Business		2
Item 6, Selected Financial Data		25
Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations		26
Item 7a, Quantitative and Qualitative Disclosures about Market Risk		67
Item 8, Financial Statements and Supplementary Data		70
Ratio of Earnings to Combined Fixed Charges
Consent of PricewaterhouseCoopers LLP
Consent of Ryder Scott Company, L.P.

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


/d		= per day
Bbl		= barrel
BBtu		= billion British thermal units
Bcf		= billion cubic feet
Bcfe		= billion cubic feet of natural gas equivalents
LNG		= liquefied natural gas
MBbls		= thousand barrels
Mcf		= thousand cubic feet
Mcfe		= thousand cubic feet of natural gas equivalents
MDth		= thousand dekatherms
MMBtu		= million British thermal units
MMcf		= million cubic feet
MMcfe		= million cubic feet of natural gas equivalents
MMWh		= thousand megawatt hours
MW		= megawatt
NGL		= natural gas liquids
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”, “the Company”, or “El Paso”, we are describing El Paso Corporation and/or our subsidiaries.

BUSINESS


	Overview

We are an energy company, originally founded in 1928 in El Paso, Texas, with a stated purpose to provide natural gas and related energy products in a safe, efficient and dependable manner. Our long-term business strategy is focused on participating in the energy industry through a rate regulated natural gas transmission business in North America and a large, independent exploration and production business operating both domestically and internationally.

Natural Gas Transmission. We own North America’s largest interstate pipeline system, which has approximately 55,500 miles of pipe that connect North America’s major producing basins to its major consuming markets. We also own approximately 420 Bcf of storage capacity and an LNG import facility with 806 MMcf of daily base load sendout capacity.

Exploration and Production. Our exploration and production business is focused on the exploration for and the acquisition, development and production of natural gas, oil and NGL in the United States and Brazil and related marketing activities. As of December 31, 2005, we held an estimated 2.4 Tcfe of proved natural gas and oil reserves in the United States and Brazil, exclusive of our equity share in the proved reserves of an unconsolidated affiliate of 253 Bcfe.

Other. We currently own or have owned other non-core assets acquired as part of a number of mergers and acquisitions and growth initiatives when we expanded from a regional gas pipeline company in the mid-1990’s to an international energy company by early 2001. Since 2003, a substantial portion of these assets have been sold, have pending sales contracts or are in the process of being sold. The divestiture of these assets was targeted at improving our operating results, financial condition and liquidity, which were negatively impacted by the decline of the energy trading industry, bankruptcy of several energy industry participants and our credit downgrades.


	Business Objective and Strategy

As of December 31, 2005, we conduct our core natural gas transmission and exploration and production operations through our Pipelines, Exploration and Production and Marketing and Trading segments. We also have Power and Field Services segments. Our business segments provide a variety of energy products and services and are managed separately as each segment requires different technology and marketing strategies. For further discussion of our business segments, see the information below and in Management’s Discussion and Analysis of Financial Condition and Results of Operations. For our segment operating results and assets, see Financial Statements and Supplementary Data, Note 20. Our business strategy in each of our operating segments can be summarized as follows:


Pipelines		Enhancing the value of our transmission business through successful recontracting, continuous efficiency improvements through cost management and prudent capital spending in the United States and Mexico, while providing outstanding customer service through safe operations.

Exploration and Production		Growing our reserve base in a manner that creates shareholder value through disciplined capital allocation, cost control and portfolio management.

Marketing and Trading		Marketing our natural gas and oil production at optimal prices and managing associated price risks.

The assets remaining in our Power segment are used to serve customers under long-term power sales contracts or sell power to the open market in spot market transactions. Additionally, through the remaining assets in our Field Services segment, we provide processing and gathering services through two facilities that support our Rocky Mountain production activities.

Pipelines Segment

Our Pipelines segment provides natural gas transmission and related services through eight separate, wholly owned pipeline systems and four 50 percent owned systems that, combined, own or have interests in approximately 55,500 miles of interstate natural gas pipelines, representing the largest integrated natural gas transmission system in the United States. Our system connects 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. Our pipeline operations include access to systems in Canada and assets in Mexico. The size, connectivity and diversity of our U.S. pipeline system provides growth opportunities through infrastructure development or large scale expansion projects and gives us the capability to adapt to the dynamics of shifting supply and demand.

We also own or have interests in approximately 420 Bcf of storage capacity through our wholly owned transmission systems and two wholly owned and three partially owned storage systems used to provide a variety of flexible services to our customers. We also have one LNG receiving terminal and related facilities at Elba Island, Georgia.

Each of our U.S. pipeline systems and storage facilities operate under Federal Energy Regulatory Commission (FERC) approved tariffs that establish rates, cost recovery mechanisms, terms and conditions of service to our customers. 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 consist of two types of revenues:


	Reservation revenues. Reservation revenues are from customers (referred to as firm customers) that 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. Usage revenues are from both firm customers and interruptible customers (those without reserved capacity) that pay usage charges based on the volume of gas actually transported, stored, injected or withdrawn.

In 2005, approximately 79 percent of our revenues were attributable to reservation charges paid by firm customers. The remaining 21 percent of our revenues were variable. Because of 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 changes in natural gas prices and market conditions, regulatory actions, competition, weather and the creditworthiness of our customers. We also experience volatility when the amounts of natural gas utilized in our operations differ from the amounts we recover from our customers for that purpose.

Our strategy is to enhance the value of our transmission business through:


	•	Seeking to expand our systems by attracting new customers, markets or supply sources while leveraging our existing assets to the extent possible;

	•	Recontracting or contracting available or expiring capacity and resolving open rate cases;

	•	Focusing on efficiency in our operations and cost control, including efficiencies that may be available across our systems or due to the coast-to-coast scale of our operations;

	•	Investing in maintenance and pipeline integrity projects to maintain the value and ensure the safety of our pipeline systems and assets;

	•	Providing outstanding customer service; and

	•	Providing natural gas transmission and related services through safe operations.

Wholly Owned Interstate Transmission Systems

Below is a further discussion of our wholly owned pipeline systems.


		As of December 31, 2005
										Average Throughput⁽¹⁾
Transmission	Supply and	Miles of		Design			Storage
System	Market Region	Pipeline		Capacity			Capacity			2005		2004		2003

				(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.		14,100		6,876			90			4,443		4,469		4,710
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		6,775			192			4,100		4,067		4,232
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.		10,700		5,650	⁽²⁾		—	⁽³⁾		4,053		4,074		3,874
Southern Natural Gas (SNG)	Extends from natural gas fields in Texas, Louisiana, Mississippi, Alabama and the Gulf of Mexico to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina and Tennessee, including the metropolitan areas of Atlanta and Birmingham.		7,700		3,450			60			1,984		2,163		2,101
Colorado Interstate Gas (CIG)	Extends from production areas in the Rocky Mountain region and the Anadarko Basin to the front range of the Rocky Mountains and multiple interconnections with pipeline systems transporting gas to the midwest, the southwest, California and the Pacific northwest.		4,000		3,000			29			1,902		1,744		1,685


		As of December 31, 2005
								Average Throughput⁽¹⁾
Transmission	Supply and	Miles of		Design		Storage
System	Market Region	Pipeline		Capacity		Capacity		2005		2004		2003

				(MMcf/d)		(Bcf)				(BBtu/d)
Wyoming Interstate (WIC)	Extends from western Wyoming and the Powder River Basin to various pipeline interconnections near Cheyenne, Wyoming.		600		1,997		—		1,479		1,201		1,213
Mojave Pipeline (MPC)	Connects with the EPNG system near Cadiz, California, the EPNG and Transwestern systems at Topock, Arizona and to the Kern River Gas Transmission Company system in California. This system also extends to customers in the vicinity of Bakersfield, California.		400		407		—		161		161		192
Cheyenne Plains Gas Pipeline (CPG)	Extends from the Cheyenne hub in Colorado to various pipeline interconnections near Greensburg, Kansas.		400		757		—		433		89		—


⁽¹⁾	Includes throughput transported on behalf of affiliates.
⁽²⁾	This capacity reflects winter-sustainable west-flow capacity of 4,850 MMcf/d and approximately 800 MMcf/d of east-end delivery capacity.
⁽³⁾	Effective January 1, 2006, EPNG began offering interruptible storage service from a storage facility that has a maximum working capacity of up to approximately 44 Bcf.

We also have a number of pipeline expansion projects underway as of December 31, 2005, which are in various stages of certification and approval. Below are the more significant projects that have been approved by the FERC:


					Anticipated
Project		Capacity		Description	Completion Date

		(MMcf/d)
ANR
	Wisconsin 2006 expansion		164	To construct and operate a 3.8 mile, 30-inch pipeline extension of the Madison Lateral Loop, a 3.1 mile, 16-inch pipeline loop⁽¹⁾of the Little Chute Lateral in Outagamie County, a 20,620 horsepower compressor station, a 2,370 horsepower compressor unit at the Janesville compressor station, and upgrades of five existing meter stations in various counties in Wisconsin.		November 2006

TGP
	Triple-T expansion		200	To construct 6.2 miles of 24-inch pipeline to extend its existing 30-inch Triple-T Line, beginning in Eugene Island Block 349, to interconnect with Enterprise Products Partners’ Anaconda System on the EI 371 platform, as well as associated piping and other appurtenant facilities.		August 2006
	Northeast ConneXion-NY/NJ		49	To modify an existing dehydration tower, filed jointly with National Fuel, serving the Hebron Storage Field in Potter County, Pennsylvania, expand capacity on Line 300, located in Bradford and Susquehanna Counties, Pennsylvania by building 6 miles of loop⁽¹⁾line, add compression facilities at Compressor Station 313 in Potter County, Pennsylvania, and at Station 317 in Bradford County, Pennsylvania, upgrade Ramsey Meter Station in Bergen County, New Jersey, and use additional incremental capacity resulting from the replacement of compression facilities at Station 325 in Sussex County, New Jersey.		November 2006
	Louisiana Deepwater Link		850	To construct a 300 foot extension of its 20-inch Grand Isle supply lateral, construct 2,100 feet of 24-inch West Delta supply lateral, abandon 3,100 feet of the 20-inch line connected to the Grand Isle platform, and install appurtenant facilities on Enterprise’s Independence Hub platform located in Mississippi Canyon Block 920.		October 2006

WIC
	Piceance Basin expansion		333	To construct and operate approximately 142 miles of 24-inch pipeline, compression and metering facilities to move additional supplies into the WIC system.		March 2006


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

Partially Owned Interstate Transmission Systems


		As of December 31, 2005						Average
								Throughput⁽²⁾
Transmission	Supply and	Ownership		Miles of		Design
System⁽¹⁾	Market Region	Interest		Pipeline⁽²⁾		Capacity⁽²⁾		2005		2004		2003

		(Percent)				(MMcf/d)		(BBtu/d)
Florida Gas Transmission⁽³⁾	Extends from south Texas to south Florida.		50		4,867		2,090		1,916		2,014		1,963
Great Lakes Gas Transmission	Extends from the Manitoba-Minnesota border to the Michigan-Ontario border at St. Clair, Michigan.		50		2,115		2,500		2,376		2,200		2,366
Samalayuca Pipeline and Gloria a Dios Compression Station	Extends from U.S.-Mexico border to the State of Chihuahua, Mexico.		50		23		460		423		433		409
San Fernando Pipeline	Extends from Pemex Compression Station 19 to the Pemex metering station in San Fernando, Mexico in the State of Tamaulipas.		50		71		1,000		951		951		130


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

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, 2005

Ownership

Storage

Storage Entity

Interest

Capacity⁽¹⁾

Location

(Percent)

(Bcf)

Bear Creek Storage

100

Louisiana

ANR Storage

100

Michigan

Blue Lake Gas Storage

Michigan

Eaton Rapids Gas Storage⁽²⁾

Michigan

Young Gas Storage⁽²⁾

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, 2005.

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 recently completed expansion of the Elba Island facility increased the peak sendout capacity to 1,215 MMcf/d and the base load sendout capacity to 806 MMcf/d. The capacity at the terminal is contracted with subsidiaries of British Gas Group and Royal Dutch Shell PLC.

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 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 their delivery capabilities and operational flexibility and complementing traditional supply transported into market areas. However, these LNG delivery systems also may compete with our pipelines for transportation of gas into market areas we serve.

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

Our existing contracts mature at various times and in varying amounts of throughput capacity. Our ability to extend our existing contracts or remarket expiring capacity is dependent on 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 requirements, we attempt to recontract or remarket our capacity at the 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. The table below shows the contracted capacity that expires by year over the next five years and thereafter.

Contract Expirations

The following table details the markets we serve and the competition faced by each of our wholly owned pipeline transmission systems as of December 31, 2005:

TGP


Customer Information	Contract Information	Competition

Approximately 466 firm and interruptible customers, none of which individually represents more than 10 percent of revenues	Approximately 481 firm transportation 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 fields from the pipeline, relative basis pricing of the pipeline receipt points, and costs of intermediate gathering or required processing of the natural gas to be transported may influence determinations of whether natural gas is ultimately attached to our system.

ANR


Customer Information	Contract Information	Competition

Approximately 297 firm and interruptible customers Major Customer: We Energies (829 BBtu/d)	Approximately 634 firm transportation contracts. Weighted average remaining contract term of approximately five years. Contract terms expire in 2006-2010.	ANR’s principal markets are in the midwest where it competes with other interstate and intrastate pipeline companies and local distribution companies to provide natural gas transportation and storage services. ANR 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 other interstate pipelines in the midwest market to serve electric generation and local distribution companies. 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 Wisconsin and the Chicago area and Gulf of Mexico sources, including deepwater production and LNG imports.

EPNG


Customer Information	Contract Information	Competition

Approximately 163 firm and interruptible customers Major Customers: Southern California Gas Company (453 BBtu/d) (93 BBtu/d) (768 BBtu/d)	Approximately 251 firm transportation contracts. Weighted average remaining contract term of approximately four years. Contract term expires in 2006. Contract term expire in 2007. Contract terms expire in 2009-2011.	EPNG faces competition in the west and southwest from other existing and proposed pipelines, from California storage facilities, and alternative energy sources that are used to generate electricity such as hydroelectric power, nuclear, coal and fuel oil. In addition, initiatives to bring LNG into California and northern Mexico are underway.
Southwest Gas Corporation (12 BBtu/d) (470 BBtu/d) (74 BBtu/d)	Contract term expires in 2006. Contract term expires in 2011. Contract term expires in 2015.

SNG


Customer Information	Contract Information	Competition

Approximately 225 firm and interruptible customers Major Customers: Atlanta Gas Light Company (959 BBtu/d) Southern Company Services (418 BBtu/d) Alabama Gas Corporation (415 BBtu/d) Scana Corporation (346 BBtu/d)	Approximately 181 firm transportation contracts. Weighted average remaining contract term of approximately six years. Contract terms expire in 2008-2015. Contract terms expire in 2010-2018. Contract terms expire in 2006-2013. Contract terms expire in 2006-2019.	SNG faces strong competition in a number of its key markets. SNG competes with other interstate and intrastate pipelines for deliveries to multiple-connection customers who can take deliveries at alternative points. Natural gas delivered on our system competes with alternative energy sources used to generate electricity, such as hydroelectric power, coal and fuel oil. 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 their other customers. In addition, SNG competes with pipelines and gathering systems for connection to new supply services.

CIG


Customer Information	Contract Information	Competition

Approximately 111 firm and interruptible customers Major Customer: Public Service Company of Colorado (970 BBtu/d) (187 BBtu/d) (261 BBtu/d)	Approximately 184 firm transportation contracts. Weighted average remaining contract term of approximately five years. Contract terms expire in 2007. Contract term expires in 2008. Contract terms expires in 2009-2014.	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 an intrastate pipeline, local production from the Denver- Julesburg basin, 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 existing and proposed interstate pipelines that are directly connected to its supply sources.

WIC


Customer Information	Contract Information	Competition

Approximately 47 firm and interruptible customers Major Customers: Williams Power Company (353 BBtu/d) CIG (247 BBtu/d) Western Gas Resources (235 BBtu/d) Cantera Gas Company (226 BBtu/d)	Approximately 47 firm transportation contracts. Weighted average remaining contract term of approximately six years. Contract terms expire in 2008-2013. Contract terms expire in 2006-2016. Contract terms expire in 2007-2013. Contract terms expire in 2012-2013.	WIC competes with pipelines that are existing, proposed and currently under construction to provide transportation services to delivery points in northeast Colorado and western Wyoming. 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


Customer Information	Contract Information	Competition

Approximately 13 firm and interruptible customers Major Customers: EPNG (312 BBtu/d) Los Angeles Department of Water and Power (50 BBtu/d)	Approximately six firm transportation contracts. Weighted average remaining contract term of approximately eight years. Contract term expires in 2015. Contract term expires in 2007.	MPC faces competition from other existing and proposed pipelines, and alternative energy sources that are used to generate electricity such as hydroelectric power, nuclear, coal and fuel oil. In addition, initiatives to bring LNG into California and northern Mexico are underway.

CPG


Customer Information	Contract Information	Competition

Approximately 20 firm and interruptible customers Major Customers: Oneok Energy Services Company L.P. (195 BBtu/d) Anadarko Energy Service Company (112 BBtu/d) Encana Marketing (USA) Inc. (170 BBtu/d) Kerr McGee (83 BBtu/d)	Approximately 16 firm transportation contracts Weighted average remaining contract term of approximately nine years. Contract terms expire in 2015. Contract terms expire in 2015-2016. Contract term expires in 2015. Contract terms expire in 2015.	CPG competes directly with other interstate pipelines serving the mid-continent region. Indirectly, CPG competes with other existing and proposed interstate pipelines that transport Rocky Mountain gas to other markets.

Exploration and Production Segment

Our Exploration and Production segment’s long-term business strategy focuses on the exploration for and the acquisition, development and production of natural gas, oil and NGL in the United States and internationally. As of December 31, 2005, we controlled over 3 million net leasehold acres. During 2005, daily equivalent natural gas production averaged approximately 743 MMcfe/d and our proved natural gas and oil reserves at December 31, 2005, were approximately 2.4 Tcfe, excluding amounts related to our unconsolidated investment in Four Star Oil & Gas Company (Four Star).

Our consolidated operations are divided into the following regions:


Region		Operating Areas/Basins

United States
	Onshore	East Texas and North Louisiana Rocky Mountains
		Black Warrior Arkoma Raton Illinois
	Texas Gulf Coast	South Texas
	Gulf of Mexico and south Louisiana	Gulf of Mexico (Federal and State waters) South Louisiana
Internationally
	Brazil	Camamu, Santos, Espirito Santo and Potiguar

In addition to our consolidated operations, we own a 43.1 percent interest in Four Star, which was acquired in connection with our acquisition of Medicine Bow Energy Corporation (Medicine Bow). Four Star operates onshore in the San Juan, Permian, Hugoton and South Alabama Basins and the Gulf of Mexico. During 2005, our proportionate share of Four Star’s daily equivalent natural gas production averaged approximately 24 MMcfe/d and at December 31, 2005, proved natural gas and oil reserves, net to our interest, were 253 Bcfe.

Our business strategy has been to create value through our drilling activities and through acquisitions of assets and companies. For 2006, we expect our growth to occur principally through drilling activities. However, we believe strategic acquisitions can support our corporate objectives by:


	•	Re-shaping our portfolio toward longer-lived, shallower decline rate reserves;

	•	Leveraging operational expertise we already possess in key operating areas, geologies or techniques;

	•	Balancing our exposure to regions, basins and commodities;

	•	Achieving risk-adjusted returns competitive with those available within our existing inventory; and

	•	Increasing our reserves more rapidly by supplementing drilling activities.

Natural Gas and Oil Properties


	Natural Gas, Oil and Condensate and NGL Reserves and Production

The tables below present our estimated proved reserves as of December 31, 2005 and our 2005 production by region and summarizes our estimated proved reserves by classification as of December 31, 2005:


			Net Proved Reserves⁽¹⁾

									Total					2005
			Natural Gas		Oil/Condensate		NGL							Production
			(MMcf)		(MBbls)		(MBbls)		(MMcfe)		(Percent)			(MMcfe)

Reserves and Production by Region
United States⁽²⁾
	Onshore			1,258,329		32,007		1,207		1,457,615		60	%		109,361
	Texas Gulf Coast			392,783		2,765		9,702		467,580		20	%		77,014
	Gulf of Mexico and south Louisiana			179,654		8,456		1,653		240,311		10	%		65,432

	Total United States			1,830,766		43,228		12,562		2,165,506		90	%		251,807
Brazil				56,388		32,250		—		249,890		10	%		19,300

	Total			1,887,154		75,478		12,562		2,415,396		100	%		271,107

Unconsolidated investment in Four Star⁽³⁾⁽⁴⁾				192,895		3,349		6,668		252,996		100	%		8,844

Reserves by Classification
United States⁽²⁾
	Producing			1,175,838		19,831		9,503		1,351,841		63	%
	Non-Producing			228,173		8,750		1,507		289,716		13	%
	Undeveloped			426,755		14,647		1,552		523,949		24	%

		Total proved		1,830,766		43,228		12,562		2,165,506		100	%

Brazil
	Producing			17,260		632		—		21,052		9	%
	Non-Producing			10,162		512		—		13,234		5	%
	Undeveloped			28,966		31,106		—		215,604		86	%

		Total proved		56,388		32,250		—		249,890		100	%

Worldwide
	Producing			1,193,098		20,463		9,503		1,372,893		57	%
	Non-Producing			238,335		9,262		1,507		302,950		12	%
	Undeveloped			455,721		45,753		1,552		739,553		31	%

		Total proved		1,887,154		75,478		12,562		2,415,396		100	%

Unconsolidated investment in Four Star⁽³⁾
	Producing			154,979		3,246		5,371		206,677		82	%
	Non-Producing			3,105		20		28		3,395		1	%
	Undeveloped			34,811		83		1,269		42,924		17	%

		Total Four Star		192,895		3,349		6,668		252,996		100	%


⁽¹⁾	Net proved reserves exclude our Power segment’s equity interests in proved reserves in Indonesia and in Peru of 162,254 MMcf of natural gas and 2,058 MBbls of oil, condensate and NGL for total natural gas equivalents of 174,600 MMcfe, all net to our ownership interests. Our Power segment has completed or expects to complete the sale of these equity interests in 2006.
⁽²⁾	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.
⁽³⁾	Our share of Four Star’s proved reserves has been estimated based on an evaluation of those reserves by El Paso’s internal reservoir engineers and not by engineers of Four Star. An independent reservoir engineering firm, Ryder Scott, which was engaged by us, prepared an estimate on 86 percent of Four Star’s proved reserves. Based on the amount of Four Star’s proved reserves determined by Ryder Scott, we believe our reported reserve amounts are reasonable.
⁽⁴⁾	Represents our proportionate share of Four Star’s production since the acquisition date.

Consolidated reserve information in the tables above is based on our internal reserve report. Ryder Scott, an independent petroleum engineering firm that reports to the Audit Committee of our Board of Directors, prepared an estimate on 92 percent of our natural gas and oil reserves. Based on the amount of proved reserves determined by Ryder Scott, we believe our reported reserve amounts are reasonable. 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.

There are numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production costs, and projecting the timing of development expenditures, including many factors beyond our control. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The reserve data represents only estimates which are often different from the quantities of natural gas and oil that are ultimately recovered. The accuracy of any reserve estimate is highly dependent on the quality of available data, the accuracy of the assumptions on which they are based, and on 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.

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. 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. For further discussion of our reserves, see Financial Statements and Supplementary Data, under the heading Supplemental Natural Gas and Oil Operations.


	Acreage and Wells

Our properties are primarily in the United States and are separated into the Onshore, Texas Gulf Coast and Gulf of Mexico and south Louisiana regions. We also have properties internationally in Brazil. The following tables detail (i) our interest in developed and undeveloped acreage at December 31, 2005, (ii) our interest in natural gas and oil wells at December 31, 2005 and (iii) our exploratory and development wells drilled during the years 2003 through 2005. Any acreage in which our interest is limited to owned royalty, overriding royalty and other similar interests is excluded.


			Developed				Undeveloped				Total
Acreage
			Gross⁽¹⁾		Net⁽²⁾		Gross⁽¹⁾		Net⁽²⁾		Gross⁽¹⁾		Net⁽²⁾

United States
	Onshore			867,392		518,892		1,591,543		1,216,552		2,458,935		1,735,444
	Texas Gulf Coast			103,234		79,439		151,751		109,241		254,985		188,680
	Gulf of Mexico and south Louisiana			530,464		362,938		540,972		494,481		1,071,436		857,419

		Total		1,501,090		961,269		2,284,266		1,820,274		3,785,356		2,781,543
Brazil				49,262		17,242		1,157,268		346,788		1,206,530		364,030

		Worldwide Total		1,550,352		978,511		3,441,534		2,167,062		4,991,886		3,145,573

In the United States, our net developed acreage is concentrated primarily in the Gulf of Mexico (38 percent), Utah (12 percent), Texas (10 percent), Oklahoma (9 percent), Alabama (8 percent), New Mexico (8 percent) and Louisiana (6 percent). Our net undeveloped acreage is concentrated primarily in New Mexico (27 percent), the Gulf of Mexico (22 percent), Wyoming (10 percent), Louisiana (7 percent), Texas (7 percent), West Virginia (7 percent), Indiana (6 percent) and Alabama (5 percent). Approximately 14 percent, 13 percent and 10 percent of our total United States net undeveloped acreage is held under leases that have minimum remaining primary terms expiring in 2006, 2007 and 2008. Approximately 24 percent, 21 percent and 14 percent of our total Brazilian net undeveloped acreage is held under leases that have minimum remaining primary terms expiring in 2006, 2007 and 2008.


															Number of Wells
			Productive												Being Drilled at
			Natural Gas				Productive Oil				Total Productive				December 31,
			Wells				Wells				Wells				2005
Productive Wells
			Gross⁽¹⁾		Net⁽²⁾		Gross⁽¹⁾		Net⁽²⁾		Gross⁽¹⁾		Net⁽²⁾⁽³⁾		Gross⁽¹⁾		Net⁽²⁾

United States
	Onshore			3,424		2,614		514		363		3,938		2,977		36		29
	Texas Gulf Coast			831		702		—		—		831		702		—		—
	Gulf of Mexico and south Louisiana			175		115		53		35		228		150		4		1

		Total United States		4,430		3,431		567		398		4,997		3,829		40		30
Brazil				4		3		6		5		10		8		—		—

		Worldwide Total		4,434		3,434		573		403		5,007		3,837		40		30


			Net Exploratory						Net Development
			Wells Drilled⁽²⁾						Wells Drilled⁽²⁾
Wells Drilled
			2005		2004		2003		2005		2004		2003

United States
	Productive			86		13		54		279		298		272
	Dry			2		10		22		4		3		1

		Total		88		23		76		283		301		273

Brazil
	Productive			—		—		2		—		—		—
	Dry			—		1		4		—		—		—

		Total		—		1		6		—		—		—

Worldwide
	Productive			86		13		56		279		298		272
	Dry			2		11		26		4		3		1

		Total		88		24		82		283		301		273


⁽¹⁾	Gross interest reflects the total acreage or wells we participated in, regardless of our ownership interest in the acreage or wells.
⁽²⁾	Net interest is the aggregate of the fractional working interests that we have in the gross acreage, gross wells or gross drilled wells.
⁽³⁾	At December 31, 2005, we operated 3,541 of the 3,841 net productive wells.

The drilling performance 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:


				2005		2004		2003

Net Production Volumes
	United States
		Natural gas (MMcf)			206,714		238,009		338,762
		Oil, condensate and NGL (MBbls)			7,516		8,498		11,778
			Total (MMcfe)		251,807		288,994		409,432
	Brazil
		Natural gas (MMcf)			15,578		6,848		—
		Oil, condensate and NGL (MBbls)			620		320		—
			Total (MMcfe)		19,300		8,772		—
	Worldwide
		Natural gas (MMcf)			222,292		244,857		338,762
		Oil, condensate and NGL (MBbls)			8,136		8,818		11,778
			Total (MMcfe)		271,107		297,766		409,432

Natural Gas Average Realized Sales Price ($/Mcf)⁽¹⁾
	United States
		Excluding hedges		$	7.92	$	6.02	$	5.51
		Including hedges		$	6.69	$	5.94	$	5.40
	Brazil
		Excluding hedges		$	2.33	$	2.01	$	—
		Including hedges		$	2.33	$	2.01	$	—
	Worldwide
		Excluding hedges		$	7.53	$	5.90	$	5.51
		Including hedges		$	6.39	$	5.83	$	5.40

Oil, Condensate, and NGL Average Realized Sales Price ($/Bbl)⁽¹⁾
	United States
		Excluding hedges		$	45.86	$	34.44	$	26.64
		Including hedges		$	45.86	$	34.44	$	25.96
	Brazil
		Excluding hedges		$	53.42	$	43.01	$	—
		Including hedges		$	42.42	$	39.19	$	—
	Worldwide
		Excluding hedges		$	46.43	$	34.75	$	26.64
		Including hedges		$	45.60	$	34.61	$	25.96

Average Transportation Cost
	United States
		Natural gas ($/Mcf)		$	0.20	$	0.17	$	0.18
		Oil, condensate and NGL ($/Bbl)		$	0.69	$	1.16	$	1.05
	Worldwide
		Natural gas ($/Mcf)		$	0.18	$	0.17	$	0.18
		Oil, condensate and NGL ($/Bbl)		$	0.63	$	1.12	$	1.05


				2005		2004		2003

Average Production Cost($/Mcfe)⁽²⁾
	United States
		Average lease operating cost		$	0.73	$	0.62	$	0.42
		Average production taxes			0.27		0.11		0.14

			Total production cost	$	1.00	$	0.73	$	0.56

	Brazil
		Average lease operating cost		$	0.42	$	—	$	—

	Worldwide
		Average lease operating cost		$	0.72	$	0.60	$	0.42
		Average production taxes			0.24		0.11		0.14

			Total production cost	$	0.96	$	0.71	$	0.56


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


	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:


				2005		2004		2003

				(In millions)
United States
	Acquisition Costs:
		Proved		$	643	$	33	$	10
		Unproved			143		32		35
	Development Costs				503		395		668
	Exploration Costs:
		Delay rentals			3		7		6
		Seismic acquisition and reprocessing			7		29		56
		Drilling			133		149		405
	Asset Retirement Obligations⁽¹⁾				1		30		124

		Total full cost pool expenditures			1,433		675		1,304
		Non-full cost pool expenditures			22		11		17

			Total cost incurred⁽²⁾	$	1,455	$	686	$	1,321

	Acquisition of unconsolidated investment in Four Star ⁽²⁾			$	769	$	—	$	—

Brazil and Other International
	Acquisition Costs:
		Proved		$	8	$	69	$	—
		Unproved			1		3		4
	Development Costs				6		1		—
	Exploration Costs:
		Seismic acquisition and reprocessing			7		15		11
		Drilling			8		10		84
	Asset Retirement Obligations				—		3		—

		Total full cost pool expenditures			30		101		99
		Non-full cost pool expenditures			—		3		1

			Total cost incurred	$	30	$	104	$	100


				2005		2004		2003

				(In millions)
Worldwide
	Acquisition Costs:
		Proved		$	651	$	102	$	10
		Unproved			144		35		39
	Development Costs				509		396		668
	Exploration Costs:
		Delay rentals			3		7		6
		Seismic acquisition and reprocessing			14		44		67
		Drilling			141		159		489
	Asset Retirement Obligations⁽¹⁾				1		33		124

		Total full cost pool expenditures			1,463		776		1,403
		Non-full cost pool expenditures			22		14		18

			Total cost incurred⁽²⁾	$	1,485	$	790	$	1,421

	Acquisition of unconsolidated investment in Four Star ⁽²⁾			$	769	$	—	$	—


⁽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 (SFAS) No. 143.

⁽²⁾	Includes $179 million of deferred income tax adjustments related to the acquisition of full-cost pool properties and $217 million related to the acquisition of our unconsolidated investment in Four Star.

We spent approximately $247 million in 2005, $156 million in 2004, and $220 million in 2003 to develop proved undeveloped reserves that were included in our reserve report as of January 1 of each year.


	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 this practice. We sell our NGL at market prices under monthly or long-term contracts, subject to customary adjustments. In Brazil, we sell the majority of our natural gas and oil to Petrobras, a Brazilian energy company. We also engage in hedging activities on a portion of our production to stabilize our cash flows and to reduce the risk of downward commodity price movements on sales of our production. As of December 31, 2005, in this segment we had hedged approximately 85,000 BBtu of our anticipated natural gas production in 2006 and approximately 26,000 BBtu of our anticipated natural gas production during 2007 through 2012. For a further discussion of the prices at which we have hedged our natural gas and oil production, see Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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

Marketing and Trading Segment

Our Marketing and Trading segment’s primary focus is to market our Exploration and Production segment’s natural gas and oil production and to manage the company’s price risks related to its anticipated production, primarily through the use of natural gas and oil derivative contracts. In addition, we also continue to manage and liquidate various transportation, power and other contracts remaining from our legacy trading operations, primarily entered into prior to the deterioration of the energy trading environment in 2002. We enter into contracts in this segment with both third parties and with affiliates that require physical delivery of a commodity or financial settlement which are further described below.

Production-related Natural Gas and Oil Derivatives

Our natural gas and oil contracts include options and swaps designed to provide price protection to El Paso from fluctuations in natural gas and oil prices. As of December 31, 2005, these contracts provided El Paso with floor prices, ceiling prices and fixed prices on the following volumes of future natural gas and oil production:


		2006		2007		2008		2009

Natural Gas (TBtu)
	Volumes with floor price		120		51		18		17
	Volumes with ceiling price		60		21		18		17
	Volumes with fixed prices		25		—		—		—
Oil (MBbls)
	Volumes with floor and ceiling prices		—		1,009		930		—
	Volumes with fixed prices		1,044		—		—		—


	Contracts Related to Legacy Trading Operations

Natural gas 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. Our ability to utilize our transportation capacity under these contracts is dependent on several factors, including the difference in natural gas prices at receipt and delivery locations along the pipeline system, the amount of working capital needed to use this capacity and the capacity required to meet our other long-term obligations. The following table details our transportation contracts as of December 31 2005:


	Alliance Pipeline	Enterprise Texas Pipeline	Other Pipelines

Daily capacity (MMBtu/d)	160,000	435,000	918,000⁽¹⁾
Expiration	2015	May 2006	2006 to 2028
Receipt points	AECO Canada	South Texas	Various
Delivery points	Chicago	Houston Ship Channel	Various


	⁽¹⁾	Approximately 700,000 MMBtu/ d of this capacity is contracted with our pipeline affiliates.

Other natural gas derivative contracts. As of December 31, 2005, we have eight significant physical natural gas contracts with power plants associated with our legacy trading operations. These contracts obligate us to sell gas to these plants and have various expiration dates ranging from 2009 to 2028, with expected obligations under individual contracts with third parties ranging from 32,000 to 142,000 MMBtu/d.

Power contracts. As of December 31, 2005, we held derivative contracts with Constellation Energy Commodities Group (Constellation) that swap locational differences in power prices between the Pennsylvania-New Jersey-Maryland (PJM) eastern region with those in the west PJM hub through 2013.

We also held a number of other power contracts that obligate us to supply power or manage the price risk associated with those supply contracts. These include a power supply agreement associated with our

formerly-owned Utility Contract Funding (UCF) facility for approximately 1,700 MMWh per year through 2016. During 2005, we entered into contracts that substantially offset the commodity risk associated with these power supply and power price risk management contracts. We will terminate or assign a portion of these contracts to Morgan Stanley in 2006; however, we will retain some contracts (including those related to UCF) that will expose us primarily to locational price risk in the future as any fixed price exposure is largely offset by the new contracts we entered into in 2005.


	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 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.

Power Segment

Our Power segment includes the ownership and operation of our remaining international and domestic power generation facilities. A number of our power assets have either been sold or are under sales agreements that are expected to close in the first half of 2006. These facilities primarily sell power under long-term power purchase agreements with power transmission and distribution companies owned by local governments which subject us to certain political risks. During the quarter ended March 31, 2006, our Board of Directors approved the sale of our interest in the Macae power facility in Brazil, which we sold in April 2006. As a result, we reflected the financial results of Macae as discontinued operations for all periods presented. As of December 31, 2005, we owned or had interests in 22 power facilities in 11 countries with a total generating capacity of approximately 5,406 gross MW (only significant assets and investments are listed):

El Paso

Expiration

Ownership

Gross

Year of Power

Project⁽¹⁾

Area

Interest

Capacity

Power Purchaser

Sales Contracts

Fuel Type

(Percent)

(MW)

International

Brazil

Araucaria⁽²⁾

Brazil

484

COPEL

—

Natural Gas

Manaus⁽³⁾

Brazil

100

238

Manaus Energia

2008

Oil

Porto Velho

Brazil

404

Eletronorte

2010, 2023

Oil

Rio Negro⁽³⁾

Brazil

100

158

Manaus Energia

2008

Oil

Asia⁽⁴⁾

Fauji

Pakistan

157

Pakistan Water and Power

2029

Natural Gas

Habibullah

Pakistan

136

Pakistan Water and Power

2029

Natural Gas

Sengkang

Indonesia

135

PLN

2022

Natural Gas

Central and other South America⁽⁴⁾

Aguaytia

Peru

155

Various

2005, 2006

Natural Gas

CEPP

Dominican Republic

CDEEE, Spot Market

2014

Oil

Fortuna

Panama

300

Union Fenosa

2005, 2008

Hydroelectric

Itabo

Dominican Republic

416

CDEEE and AES

2016

Oil/Coal

Europe

EMA⁽⁴⁾

Hungary

Dunaferr Energy Services

2016

Natural Gas/Oil

Domestic

Berkshire

MA - U.S.

261

—⁽⁵⁾

Natural Gas

Midland Cogeneration

MI - U.S.

1,575

Consumers Power, Dow

2025

Natural Gas


⁽¹⁾	All projects in this table are reflected as investments in unconsolidated affiliates in our financial statements.
⁽²⁾	See Financial Statements and Supplementary Data, Note 16 for a further discussion of this plant.
⁽³⁾	See Financial Statements and Supplementary Data, Note 21 for a further discussion of the transfer of ownership in 2008 of these facilities.
⁽⁴⁾	We have sold or have received approval from our Board of Directors to sell these facilities in 2006.
⁽⁵⁾	Our Marketing and Trading segment sells the power that this facility generates to the wholesale power market.

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 2005

Pipeline

Interest

Pipeline

Capacity⁽¹⁾

Throughput⁽¹⁾

(Percent)

(MMcf/d)

(BBtu/d)

Bolivia to Brazil

1,957

1,059

841

Argentina to Chile

336

138

100


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

Field Services Segment

As of December 31, 2005, our Field Services segment conducted our remaining midstream activities, which consisted principally of two processing plants that support our Exploration and Production segment activities in the Rocky Mountain area. These facilities had operational capacity of 49 MMcf/d. In January 2006, these plants were transferred to our Exploration and Production segment. As a result, our Field Services segment will cease to be a business segment in 2006.

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. Our corporate operations include our general and administrative functions as well as a telecommunications business and various other contracts and assets, including those related to petroleum ship charters, all of which were insignificant to our results in 2005. Our discontinued operations consist of our south Louisiana gathering and processing assets (previously part of the Field Services segment), certain of our international power operations in Brazil, Central America and Asia, certain of our international natural gas and oil production operations (primarily in Canada), our petroleum markets business and our coal mining operations.

Regulatory Environment

Pipelines. Our interstate natural gas transmission systems and storage operations are regulated by the FERC under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005. Each of our pipeline systems and storage facilities operates under tariffs approved by the FERC that establish rates, cost recovery mechanisms, and terms and conditions for service to our customers. Generally, the FERC’s authority extends to:


	•	rates and charges for natural gas transportation, storage, LNG 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.

Our interstate pipeline systems are also subject to federal, state and local pipeline and LNG plant safety and environmental statutes and regulations by the U.S. Department of Transportation, U.S. Department of the Interior, and U.S. Coast Guard. Our systems have ongoing programs designed to keep our facilities in compliance with these safety and environmental requirements.

Exploration and Production. Our natural gas and oil exploration and production activities are regulated at the federal, state and local levels, as well as in Brazil. 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 Brazilian oil and natural gas operations are subject to environmental regulations administered by the Brazilian government, which includes political subdivisions in that country. 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. In addition, we maintain insurance to limit exposure to sudden and accidental spills and oil pollution liability.

International and Domestic Power. Our remaining international power generation activities are regulated by governmental agencies in the countries in which these projects are located. Many of these

countries have developed 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.

Our remaining 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. Power production activities at these plants are regulated by the FERC under the Public Utility Regulatory Policies Act of 1978 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.

Field Services. Our remaining operations 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.

Environmental

A description of our environmental activities is included in Financial Statements and Supplementary Data, Note 16.

Employees

As of February 24, 2006, we had approximately 5,700 full-time employees, of which 310 employees are subject to collective bargaining arrangements.

Executive Officers of the Registrant

Our executive officers as of February 27, 2006, are listed below.


		Officer
Name	Office	Since		Age

Douglas L. Foshee	President and Chief Executive Officer of El Paso		2003		46
D. Mark Leland	Executive Vice President and Chief Financial Officer of El Paso		2005		44
Robert W. Baker	Executive Vice President and General Counsel of El Paso		2002		49
Lisa A. Stewart	Executive Vice President of El Paso and President of El Paso Exploration & Production Company		2004		48
Susan B. Ortenstone	Senior Vice President (Human Resources and Administration) of El Paso		2003		49
Stephen C. Beasley	President of Eastern Pipeline Group		2005		54
James J. Cleary	President of Western Pipeline Group		2005		51
James C. Yardley	President of Southern Pipeline Group		2005		54
Daniel B. Martin	Senior Vice President of Pipeline Operations		2005		49

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 worked at Torch Energy Advisors Inc. in various capacities, including Chief Operating Officer and Chief Executive Officer.

D. Mark Leland has been Executive Vice President and Chief Financial Officer of El Paso since August 2005. Mr. Leland served as Executive Vice President of El Paso Exploration & Production Company (formerly known as El Paso Production Holding Company) from January 2004 to August 2005, and also as Chief Financial Officer and a director from April 2004 to August 2005. He served in various capacities for GulfTerra Energy Partners, L.P. and its general partner, including as Senior Vice President and Chief

Operating Officer from January 2003 to December 2003, as Senior Vice President and Controller from July 2000 to January 2003, and as Vice President from August 1998 to July 2000. Mr. Leland has also worked in various capacities for El Paso Field Services from 1997 to August 2005.

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 worked in various capacities in the legal department of Tenneco Energy and El Paso since 1983.

Lisa A. Stewart has been an Executive Vice President of El Paso since November 2004, and President of El Paso Exploration & Production Company 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 capacities for Apache Corporation.

Susan B. Ortenstone has been Senior Vice President of El Paso since October 2003. Ms. Ortenstone was Chief Executive Officer for Epic Energy Pty Ltd. from January 2001 to June 2003. She served as Vice President of El Paso Gas Services Company and President of El Paso Energy Communications from December 1997 to December 2000. Prior to that time Ms. Ortenstone worked in various strategy, marketing, business development, engineering, and operations capacities since 1979.

Stephen C. Beasley has been Chairman of the Board and President of ANR Pipeline Company and Tennessee Pipeline Company since May 2005. He has been Director of ANR Pipeline Company since January 2004, Director of Tennessee Gas Pipeline Company since November 2001 and President of Tennessee Pipeline Company since June 2001. Prior to that time, Mr. Beasley worked in various capacities at Tennessee Gas Pipeline since 1987.

James J. Cleary has been Chairman of the Board and President of El Paso Natural Gas Company and Colorado Interstate Gas Company since May 2005. He has been Director and President of El Paso Natural Gas Company and Colorado Interstate Gas Company since January 2004. From January 2001 through December 2003, he served as President of ANR Pipeline Company. Prior to that time, Mr. Cleary served as Executive Vice President of Southern Natural Gas Company from May 1998 to January 2001. He also worked for Southern Natural Gas Company and its affiliates in various capacities since 1979.

James C. Yardley has been Chairman of the Board and President of Southern Natural Gas Company since May 2005, Director of Southern Natural Gas Company since November 2001 and President of Southern Natural Gas Company since May 1998. He served as Vice President, Marketing and Business Development for Southern Natural Gas Company from April 1994 to April 1998. Prior to that time, Mr. Yardley worked in various capacities with Southern Natural Gas and Sonat Inc. since 1978.

Daniel B. Martin has been Director of ANR Pipeline Company, Colorado Interstate Gas Company, El Paso Natural Gas Company, Southern Natural Gas Company and Tennessee Gas Pipeline Company since May 2005. He has been Senior Vice President of El Paso Natural Gas Company since February 2000, Senior Vice President of Southern Natural Gas Company and Tennessee Gas Pipeline Company since June 2000 and Senior Vice President of ANR Pipeline Company and Colorado Interstate Gas Company since January 2001. Prior to that time, Mr. Martin worked in various capacities with Tennessee Gas Pipeline Company since 1978.

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.

SELECTED FINANCIAL DATA

The following historical selected financial data excludes our south Louisiana gathering and processing operations, certain international power operations, certain of our international natural gas and oil production operations and our petroleum markets and coal mining businesses, all of which are presented as discontinued operations in our financial statements for all periods. The selected financial data below should be read together with Management’s Discussion and Analysis of Financial Condition and Results of Operations and Financial Statements and Supplementary Data included in this Current Report on Form 8-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,

		2005			2004			2003			2002			2001

		(In millions, except per common share amounts)
Operating Results Data:
	Operating revenues⁽¹⁾	$	3,970		$	5,288		$	6,158		$	6,455		$	9,871
	Loss from continuing operations⁽²⁾	$	(352	)	$	(904	)	$	(662	)	$	(1,336	)	$	(267	)
	Net loss available to common stockholders	$	(633	)	$	(947	)	$	(1,883	)	$	(1,875	)	$	(447	)
	Basic and diluted loss per common share from continuing operations	$	(0.59	)	$	(1.41	)	$	(1.11	)	$	(2.39	)	$	(0.53	)
	Cash dividends declared per common share	$	0.16		$	0.16		$	0.16		$	0.87		$	0.85
	Basic and diluted average common shares outstanding		646			639			597			560			505
Financial Position Data:
	Total assets⁽¹⁾	$	31,838		$	31,383		$	36,968		$	41,947		$	44,273
	Long-term financing obligations⁽³⁾		17,023			18,241			20,000			16,105			12,690
	Securities of subsidiaries⁽³⁾		31			367			447			3,421			4,013
	Stockholders’ equity		3,389			3,438			4,346			5,749			6,666


⁽¹⁾		Decreases were a result of asset sales activities during these periods. See Financial Statements and Supplementary Data, Note 3.
⁽²⁾		We incurred net losses of $42 million in 2005, $1.1 billion in 2004, $1.2 billion in 2003 and $0.9 billion in 2002 related to gains, losses and impairments of assets and equity investments as well as restructuring charges related to industry changes and the realignment of our businesses under our strategic plan. 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 $59 million in 2005, $104 million in 2003 and $899 million in 2002, before income taxes. In addition, we incurred ceiling test charges of $5 million, $5 million and $1.9 billion in 2003, 2002 and 2001 on our full cost natural gas and oil properties. During 2001, we merged with The Coastal Corporation and incurred costs and asset impairments related to this merger that totaled approximately $1.5 billion. For further discussions of events affecting comparability of our results in 2005, 2004 and 2003, see Financial Statements and Supplementary Data, Notes 2 through 5.
⁽³⁾		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 in 2003, 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.

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 in our Annual Report on Form 10-K, beginning on page 24.

During 2005, we discontinued our south Louisiana gathering and processing operations (previously part of our Field Services segment) and our international power operations at our Nejapa, CEBU and East Asia Utilities power plants. In March 2006, our Board of Directors approved the sale of our interest in Macae, a power plant in Brazil. Our operating results for all periods presented reflect each of these operations as discontinued.

Overview

Business Purpose and Description. 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 and oil producer. We also maintain an energy marketing and trading business that supports the marketing of our natural gas and oil production and the management of the risk associated with commodity prices.

During the past several years we have sold nearly $12 billion of assets to reduce debt and improve liquidity. These businesses were either not core to our long-term objectives or were performing below the expectations we had for them at the time we made the investment. These divestitures have resulted in significant financial losses through asset impairments, realized losses on asset sales and reduction of income from the businesses sold. We have sold substantially all of our power and midstream assets and in 2006 we expect to be substantially complete with the divestiture of our non-core activities.

Drivers of our Profitability. Our future profitability will be driven by a number of factors including our ability to:

Pipelines


	—	Expand our existing pipeline systems and gain access to new supply areas and sources
	—	Contract and recontract pipeline capacity with our customers
	—	Successfully resolve our pending rate cases
	—	Improve operational efficiency

Exploration and Production / Marketing and Trading


	—	Increase our natural gas and oil proved reserve base and production volumes through successful drilling programs or acquisitions and efficient operations
	—	Manage commodity price risk to optimize the amounts we receive for the commodities we sell

Other


	—	Successfully manage and complete the orderly exit of our legacy assets and trading positions
	—	Successfully resolve legacy contingencies
	—	Reduce debt levels and interest costs

Summary of Operational/ Financial Performance in 2005. During 2005, we continued to develop our core pipeline and exploration and production operations. Our pipelines delivered strong financial performance and our exploration and production business stabilized. However, our earnings were negatively impacted by substantial mark-to-market losses on our natural gas and power derivative contracts due to commodity price increases, impairment charges taken in conjunction with the divestiture of non-core assets and accruals for potential obligations related to various legacy matters. Additionally, the impact of Hurricanes Katrina and Rita affected our pipeline and production operations in the second half of 2005. Listed below and in the individual segment results that follow is a further discussion of the events affecting 2005 as well as progress in our key areas of focus:


Area of Operations		Events Affecting Operations


Pipelines		Finalized new rates at Southern Natural Gas Company.

		Re-contracted or contracted available or expiring capacity.

		Proceeded with several pipeline expansion projects in our pipeline systems and at our Elba Island LNG facility.

		Incurred significant damage to sections of our Gulf Coast and offshore pipeline facilities due to Hurricanes Katrina and Rita. These hurricanes also resulted in the shut-in of a significant portion of gas supply on our systems.

E & P and Marketing and Trading		Completed the turnaround of our exploration and production business by (i) stabilizing production rates, in spite of incurring a reduction of our annual production of approximately 12 Bcfe as a result of Hurricanes Katrina and Rita and (ii) growing our reserve base through our capital drilling program and through four acquisitions of natural gas and oil properties, including our acquisition of Medicine Bow.

		Sold our natural gas and oil production at higher commodity prices. However, we incurred substantial losses associated with derivative contracts used to provide price protection on our production and in settling hedges that had been put in place during a lower price environment.

		Assigned or terminated the majority of our power contracts, our Cordova tolling agreement and the remaining derivative contracts associated with our power contract restructuring operations.

Other		Completed or announced the divestiture of substantially all of our remaining operations in our midstream, power and other businesses, for total proceeds of approximately $2.4 billion ($2.0 billion through December 31, 2005). The net effect of these sales activities resulted in substantial losses in 2005.

		Furthered legal and contractual disputes, including those related to our Brazilian power plants and domestic legal matters.

What to Expect Going Forward. For 2006, our pipeline operations are positioned to provide steady operating results based on the current levels of contracted capacity, expansion plans and the status of rate and regulatory actions. Our exploration and production operating results will be driven by continued success of our drilling programs, our ability to restore the remaining production that has been shut-in since late September 2005 due to Hurricane Rita, our ability to manage increases in the cost of production services and continued high commodity prices. Additionally, a substantial portion of our below-market derivative contracts are scheduled to expire in 2006, which will give us a greater opportunity to participate in the higher commodity pricing environment.

In 2006, we will also strive to achieve our net debt (debt, less cash) target of $14 billion by year-end, complete the sale of our Asian and Central American power assets (substantially all of which are under contract), pursue the divestiture of our remaining domestic power assets and complete the resolution of the issues related to our Brazilian power investments as well as other remaining legacy issues.

Liquidity

Overview. The year 2005 was a turning point for us in terms of our liquidity and capital resources. We began the year focused on reducing liquidity concerns, strengthening our credit metrics, selling a number of non-core assets and businesses and reducing cash flow risks associated with a number of derivative transactions put in place in prior years. During 2005, we (i) completed asset sales for proceeds of $2.0 billion, (ii) replaced some of our cash margining requirements with letters of credit and (iii) entered into or completed transactions to divest or reduce the risk of a substantial portion of our power portfolio, including our Cordova tolling agreement. While we continue to closely monitor our liquidity, we believe the events of 2005 and those over the past several years have allowed us to turn our attention in 2006 to expanding our core businesses of natural gas pipelines and exploration and production.

Available Liquidity. We rely on cash generated from our operations as a significant source of liquidity. We supplement this, as needed, through the use of available credit facilities, project and bank financings, proceeds from asset sales and the issuance of debt, preferred securities and equity securities. Our subsidiaries are a significant 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 this 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. 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. As of December 31, 2005, we had available liquidity as follows:


	(In billions)

Available cash	$	2.0
Available capacity under our credit agreements⁽¹⁾		0.3

Net available liquidity at December 31, 2005	$	2.3


⁽¹⁾	See discussion of Capital Resources on page 42.

Expected 2006 Cash Flows. In addition to our available liquidity, we expect to generate significant operating cash flow in 2006, which we will supplement with $1.2 billion of expected proceeds from asset sales, including $0.4 billion of cash upon completing the assignment of a majority of our power derivative portfolio. We expect to also generate cash from financing activities as needed, including the anticipated issuance of common stock during the year.

In 2006, we expect to spend approximately $2.0 billion on capital investments in our core pipeline and exploration and production businesses, intended to both maintain and grow these businesses. Our capital program for 2006 is forecasted as follows (in billions):


				Exploration and
		Pipelines		Production		Total

Maintenance		$	0.5	$	0.7	$	1.2
Growth			0.5		0.3		0.8

	Total	$	1.0	$	1.0	$	2.0

As of December 31, 2005, we had debt maturities for 2006 and 2007 of approximately $0.4 billion and $0.9 billion. We also had approximately $0.6 billion of zero-coupon debentures with a stated maturity of 2021 that the holders required us to redeem for cash in February 2006. In 2007, we have approximately $0.6 billion of debt that the holders can require us to redeem which, when combined with our maturities, could require us to retire up to $1.4 billion of debt in 2007. In addition, as of December 31, 2005, we have $225 million of project debt related to Macae which is included in liabilities related to discontinued operations and was redeemed in April 2006.

Factors Impacting our Liquidity. Each of our existing and future sources of cash is 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 and the extent to which we hedge our natural gas and oil production, demands for our

commodities or services, success in recontracting existing pipeline capacity contracts, drilling success and competition from other providers or alternative energy sources. Collateral demands or recovery of cash posted as collateral are impacted by commodity 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, the number of interested buyers and our ability to successfully complete the transaction. In addition, our future liquidity will be impacted by our ability to access capital markets which may be restricted due to our credit ratings and general market conditions. The following is a further discussion of some of these factors and their impact on us in 2005 or potential impact in future periods.


	•	Price Risk Management Activities. We enter into derivative contracts to provide price protection on a portion of our anticipated natural gas and oil production. Specifically, our Exploration and Production and Marketing and Trading segments use swap and option contracts to fix the amount of cash we will receive on contracted volumes sold or to provide floor or ceiling prices on these volumes. Floor prices are the minimum cash prices to be received and ceiling prices are the maximum cash prices to be received under the option contracts.

As of December 31, 2005, a number of our swap contracts have been designated as and are accounted for as accounting hedges. However, our option contracts and certain other swap contracts have not been designated as hedges and are therefore marked-to-market through earnings each period. The accounting method used for these contracts affects the timing of the income or loss recognized on any individual contract in periods prior to its settlement. However, through the settlement date, the cumulative income or loss and cash flow impacts of a contract are identical whether or not it is accounted for as a hedge or is marked-to-market through earnings each period. For a further discussion of the income impacts of these contracts, see our Exploration and Production and Marketing and Trading segments’ discussions of operating results. The following table shows the contracted volumes and the minimum, maximum and average cash prices that we will ultimately receive under these contracts upon settlement or when the underlying production is sold:


	Swaps⁽¹⁾				Floors⁽¹⁾				Ceilings⁽¹⁾

			Average				Average				Average
	Volumes		Price		Volumes		Price		Volumes		Price
Natural Gas
2006		110	$	4.89		120	$	7.00		60	$	9.50
2007		5	$	3.56		51	$	6.41		21	$	9.00
2008		5	$	3.42		18	$	6.00		18	$	10.00
2009-2012		16	$	3.74		17	$	6.00		17	$	8.75
Oil
2006		1,428	$	52.45		—		—		—		—
2007		192	$	35.15		1,009	$	55.00		1,009	$	60.38
2008		—		—		930	$	55.00		930	$	57.03


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


	•	Cash Margining Requirements on Derivative Contracts. A substantial portion of our natural gas and oil derivative contracts are at prices significantly below current market prices, which has resulted in us posting substantial cash margin deposits with the counterparties for the value of these instruments. During 2005, we experienced volatility in the level of margins posted, primarily resulting from the increase in commodity prices as a result of Hurricanes Katrina and Rita. The resulting increased commodity prices required us to post $0.7 billion of additional cash margin deposits with counterparties to our derivative contracts. In the fourth quarter of 2005, $0.5 billion of margin deposits had been returned to us due to a decrease in prices and settlements, but these cash recoveries were largely offset by cash collateral requirements relating to an agreement we entered into to assign a majority of the contracts in our power portfolio to a third party. In 2006, we expect approximately $1.2 billion of collateral supported by both cash margin deposits and letters of credit, to be returned to us, which includes the collateral that we anticipate to receive upon completion of the assignment of the positions


		related to our power portfolio in December 2005. If commodity prices decrease, we could recover some of this amount earlier than anticipated.


		Any future increases in prices could have a significant impact on our operating cash flows as additional margin deposits would be required. Based on our derivative positions at December 31, 2005, a $0.10/MMBtu increase in the price of natural gas would result in an increase in our margin requirements by $19 million for transactions that settle in 2006, $6 million for transactions that settle in 2007, $5 million for transactions that settle in 2008 and $13 million for transactions that settle in 2009 and thereafter.

	•	Hurricanes. Hurricanes Katrina and Rita impacted virtually all producers and transporters doing business in the Gulf of Mexico region. We incurred significant damage to our property, including our transmission facilities. To date, we estimate total repair costs related to these storms to be approximately $457 million, of which $380 million is claimed through our property damage insurer, which is a mutual insurance company that is subject to individual and aggregate loss limits by event. Based on the level of our claims and the claims of all insured parties, we will not receive a portion of the costs we will incur to repair our systems. Based on current estimates, we anticipate that up to $164 million of capital and maintenance expenditures claimed through our property damage insurer will not be recovered due to these limits. Also, the timing of reimbursements we will receive may occur later than the capital expenditures on the damaged facilities, which may increase our net capital expenditures for 2006 and could negatively impact our estimates of cash flow.

Despite the impact of the factors above, we were able to largely mitigate the effects of these items in 2005 through the successful completion of a number of asset sales, the issuance of $400 million of notes by CIG and by entering into a six month, $400 million revolving borrowing base credit agreement (with an initial borrowing capacity of $300 million). We believe we will have sufficient liquidity to meet our ongoing liquidity and cash needs through the combination of available cash and borrowings under our credit agreements. For a further discussion of risks that may impact our cash flows, see discussion in our Annual Report on Form 10-K on page 32.

Capital Resources

Existing Financing Facilities. During 2005, we continued to reduce our overall debt as part of our strategic plan. We also issued $750 million of convertible preferred stock primarily to satisfy our remaining obligations under the Western Energy Settlement and to redeem the preferred stock of a consolidated subsidiary. Our debt activity during 2005 was as follows (in millions):


Debt obligations as of December 31, 2004⁽¹⁾	$	18,876
Principal amounts borrowed		1,638
Repayment/retirement of principal⁽¹⁾		(1,809	)
Sale of entities⁽²⁾		(575	)
Other⁽¹⁾		(121	)

Total debt as of December 31, 2005⁽¹⁾	$	18,009


⁽¹⁾	Excludes $320 million debt obligations as of December 31, 2004, $(103) million repayment/retirement of principal, and $8 million in other related to Macae resulting in $225 million as of December 31, 2005, reported in liabilities related to discontinued operations.
⁽²⁾	Related to the sale of Cedar Brakes I and II and Mohawk River Funding II.

As of December 31, 2005, we have approximately $0.3 billion of available capacity under several credit facilities as described below:


	•	$3 billion credit agreement. As of December 31, 2005, we had borrowed $1.23 billion as a term loan and issued approximately $1.7 billion of letters of credit under this credit agreement. The agreement is


		collateralized by our equity interests in TGP, EPNG, ANR, CIG, Southern Gas Storage Company (which owns an interest in Bear Creek Storage Company) and ANR Storage Company.

	•	$500 million revolving credit facility. In August 2005, our subsidiary, EEPC, entered into and borrowed $500 million under a five-year revolving credit facility bearing interest at LIBOR plus 1.875%. Amounts borrowed were used to partially fund the acquisition of Medicine Bow. The facility can be utilized for funded borrowings or for the issuance of letters of credit and is collateralized by certain EEPC natural gas and oil production properties. Our current intent is to issue $500 million to $800 million of our common stock to repay amounts borrowed under this facility and for other purposes, the timing of which is dependent on market conditions.

	•	$400 million revolving credit agreement. In November 2005, we entered into a $400 million revolving borrowing base credit agreement collateralized by certain natural gas and oil production properties owned by one of our subsidiaries, which is also a co-borrower. Under the agreement we have initial borrowing availability of $300 million. The credit agreement can be used for revolving credit loans or for the issuance of letters of credit and will mature in May 2006. As of December 31, 2005, there were no outstanding borrowings or letters of credit issued under this agreement.

The availability of borrowings under these credit agreements and our ability to incur additional debt is subject to various conditions, 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 (as defined in the credit agreement) not to exceed 6.25 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, 2005, our ratio of Debt to Consolidated EBITDA was 4.79 to 1 and our ratio of Consolidated EBITDA to interest expense and dividends was 2.15 to 1.

Overview of Cash Flow Activities for 2005 Compared to 2004

For the years ended December 31, 2005 and 2004, our cash flows are summarized as follows:


					2005			2004

					(In billions)
Cash flow from operations
	Continuing operating activities
		Net loss before discontinued operations			$	(0.4	)	$	(0.9	)
		Non-cash income items				1.3			2.3
		Changes in assets and liabilities
				Change in broker margin deposits		(0.7	)		0.1
				Settlements of derivatives designated as hedges		(0.4	)		—
				Assignment of power derivative liabilities		(0.4	)		—
				Proceeds from entering into derivative contracts		0.4			—
				Changes in other assets and liabilities		0.5			(0.6	)

			Total cash flow from operations		$	0.3		$	0.9


					2005		2004

					(In billions)
Other cash inflows
	Continuing investing activities
		Net proceeds from the sale of assets and investments			$	1.4	$	1.9
		Net proceeds from restricted cash				—		0.5
		Other				0.2		0.1

						1.6		2.5

	Continuing financing activities
		Net proceeds from the issuance of long-term debt				1.6		1.3
		Proceeds from the issuance of preferred and common stock				0.7		0.1
		Net discontinued operations activity				0.6		1.1

						2.9		2.5

			Total other cash inflows		$	4.5	$	5.0

Other cash outflows
	Continuing investing activities
		Additions to property, plant, and equipment			$	1.7	$	1.8
		Net cash paid for acquisitions				1.0		—
		Other				0.1		—

						2.8		1.8

	Continuing financing activities
		Payments to retire long-term debt and redeem preferred interests				1.6		2.4
		Payments of revolving credit facilities				—		0.9
		Redemption of preferred stock of a subsidiary				0.3		—
		Dividends paid to common stockholders				0.1		0.1

						2.0		3.4

			Total other cash outflows			4.8		5.2

				Net change in cash	$	—	$	0.7


	Cash from Continuing Operating Activities

During the year ended December 31, 2005, our net operating cash flow decreased by $0.6 billion compared to 2004, primarily due to activities associated with our derivative contracts. During 2005, we paid approximately $0.4 billion of settlements on our hedging derivatives and paid approximately $0.4 billion to assign or terminate our Cordova power contract and our contracts to supply power to Cedar Brakes I and II. In addition, we received approximately $0.4 billion to assign a portion of our power derivative portfolio to Morgan Stanley, but were required to deposit $0.4 billion of cash margin with them related to offsetting contracts we entered into until we complete the assignment. We expect to receive this cash margin back in the first half of 2006 when the original contracts are assigned and the offsetting contracts are terminated. Our cash margining requirements also increased on our other derivative contracts by an additional $0.3 billion in 2005 due to the impact of commodity price increases in 2005.

The net cash outflows of $1.1 billion associated with these derivatives and their related cash margin deposits were partially offset by a $0.5 billion increase in cash flows from our other operating activities, including a $0.2 billion decrease in the amount of our payments associated with the Western Energy Settlement in 2005 as compared to 2004.


	Cash From Continuing Investing Activities

For the year ended December 31, 2005, net cash used in our continuing investing activities was $1.2 billion. Among other items, during the year we received net proceeds of approximately $0.6 billion from

sales of our power assets as well as $0.7 billion from the sales of our general partnership interests in Enterprise and various other assets in our Field Services segment.

Our 2005 capital expenditures, including acquisitions, were as follows (in billions):


Production exploration, development and acquisition expenditures		$	1.8
Pipeline expansion, maintenance and integrity projects			0.8
Other			0.1

	Total capital expenditures and acquisitions	$	2.7


	Cash From Continuing Financing Activities

Net cash provided by our continuing financing activities was $0.9 billion for the year ended December 31, 2005. We generated cash of $2.3 billion primarily from the issuance of $0.7 billion of convertible preferred stock and $1.6 billion of long-term debt. We also had $0.6 billion of cash contributed by our discontinued operations primarily as a result of proceeds from sales of these assets. Offsetting our cash inflows were payments of $1.6 billion to retire long-term third party debt and $0.3 billion to redeem the cumulative preferred stock of a subsidiary, El Paso Tennessee Pipeline Co. (EPTP). Additionally, we paid dividends of $0.1 billion during 2005.

Off-Balance Sheet Arrangements

In the course of our business activities, we enter into a variety of financing arrangements and contractual obligations. Certain of these arrangements are often referred to as off-balance sheet arrangements and include guarantees, letters of credit and other interests in variable interest entities.

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. For example, if the guaranteed party is required to purchase services from a third party and then fails to do so, we would be required to either purchase these services or make payments to the third party to compensate them for any losses they incurred because of this non-performance. We also periodically provide indemnification arrangements related to assets or businesses we have sold. These arrangements include, but are not limited to, indemnifications for income taxes, the resolution of existing disputes, environmental matters and necessary expenditures to ensure the safety and integrity of the assets sold.

We record accruals for our guaranty and indemnification arrangements at their fair value when they are issued and subsequently adjust those accruals when we believe it is both probable that we will have to pay amounts under the arrangements and those amounts can be estimated. As of December 31, 2005, we had a liability of $91 million related to our guarantees and indemnification arrangements. These arrangements had a total stated exposure of $233 million, for which we are indemnified by third parties for $29 million. These amounts exclude guarantees for which we have issued related letters of credit discussed below.

In addition to the exposures described above, we received a ruling from a trial court, which was upheld on appeal, that we are required to indemnify a third party for benefits paid to a closed group of retirees of one of our former subsidiaries. We have a liability of approximately $380 million associated with our estimated exposure under this matter as of December 31, 2005. For a further discussion of this matter, see Financial Statements and Supplementary Data, Note 16.

Letters of Credit

We enter into letters of credit in the ordinary course of our operations as well as periodically in conjunction with sales of assets or businesses. As of December 31, 2005, we had outstanding letters of credit of approximately $2.0 billion (of which $0.2 billion related to Macae which is reported as discontinued operations), including $1.2 billion of letters of credit securing our recorded obligations related to price risk management activities.

Interests in Variable Interest Entities

We have significant interests in a number of variable interest entities, primarily investments held in our Power segment. A variable interest entity is a legal entity whose equity owners do not have sufficient equity at risk or a controlling financial interest in the entity. We are required to consolidate such entities if we are allocated the majority of the variable interest entity’s losses or return, including fees paid by the entity. If we are not the primary beneficiary of the variable interest entity’s operations, consolidation is not required; as of December 31, 2005, we do not consolidate approximately 17 variable interest entities for this reason. For additional information on these entities, including our related interests in those entities, see Financial Statements and Supplementary Data, Note 21, Investments in, Earnings from and Transactions with Unconsolidated Affiliates.

Contractual Obligations

We are party to various contractual obligations, which include the off-balance sheet arrangements described above. A portion of these obligations are reflected in our financial statements, such as short-term and long-term debt and other accrued liabilities, while other obligations, such as demand charges under transportation and storage commitments and operating leases and capital commitments, are not reflected on our balance sheet. The following table summarizes our contractual cash obligations as of December 31, 2005, for each of the years presented (all amounts are undiscounted):


		2006		2007		2008		2009		2010		Thereafter		Total

		(In millions)
Long-term financing obligations:⁽¹⁾
	Principal⁽²⁾	$	986	$	781	$	676	$	2,479	$	2,058	$	11,085	$	18,065
	Interest⁽²⁾		1,299		1,274		1,212		1,145		945		10,939		16,814
Other contractual liabilities⁽³⁾			101		47		32		15		12		50		257
Operating leases⁽⁴⁾			81		71		14		11		7		33		217
Other contractual commitments and purchase obligations:⁽⁵⁾
	Transportation and storage⁽⁶⁾		112		100		94		91		89		368		854
	Commodity purchases⁽⁷⁾		33		32		21		14		14		28		142
	Other⁽²⁾⁽⁸⁾		376		48		52		22		22		41		561

	Total contractual obligations	$	2,988	$	2,353	$	2,101	$	3,777	$	3,147	$	22,544	$	36,910


⁽¹⁾	See Financial Statements and Supplementary Data, Note 14.
⁽²⁾	Excludes $225 million of principal, $24 million of interest and $1 million of contractual commitments related to Macae which is reported in discontinued operations.
⁽³⁾	Includes contractual, environmental and other obligations included in other current and noncurrent liabilities in our balance sheet. Excludes expected contributions to our pension and other postretirement benefit plans of $61 million in 2006 and $176 million for the four year period ended December 31, 2010, because these expected contributions are not contractually required. Also excludes potential amounts due under an indemnification of a former subsidiary for benefits being paid to a closed group of retirees. We have a liability of approximately $380 million related to the litigation associated with this matter as of December 31, 2005.
⁽⁴⁾	See Financial Statements and Supplementary Data, Note 16.
⁽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 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 exploration and 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 use derivative financial instruments in our Exploration and Production and Marketing and Trading segments to manage the price risk of commodities. In the tables below, derivatives designated as hedges primarily consist of swaps used to hedge natural gas production. Other commodity-based derivative contracts relate to derivative contracts not designated as hedges, such as options, swaps, tolling agreements and other natural gas and power purchase and supply contracts, our historical energy trading activities and our power contract restructuring activities (which were fully disposed of in 2004 and 2005).

The following table details the fair value of our commodity-based derivative contracts by year of maturity and valuation methodology as of December 31, 2005:


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

				(In millions)
Derivatives designated as hedges⁽¹⁾
	Assets			$	31		$	—		$	—		$	—		$	—		$	31
	Liabilities				(570	)		(62	)		(34	)		(18	)		—			(684	)

			Total derivatives designated as hedges		(539	)		(62	)		(34	)		(18	)		—			(653	)

Other commodity-based derivatives
	Exchange-traded positions⁽¹⁾
		Assets			191			360			158			—			—			709
		Liabilities			(155	)		(1	)		—			—			—			(156	)
	Non-exchange traded positions⁽²⁾
		Assets			414			467			229			135			16			1,261
		Liabilities			(693	)		(979	)		(501	)		(377	)		(27	)		(2,577	)

			Total other commodity-based derivatives		(243	)		(153	)		(114	)		(242	)		(11	)		(763	)

	Total commodity-based derivatives			$	(782	)	$	(215	)	$	(148	)	$	(260	)	$	(11	)	$	(1,416	)


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

⁽²⁾	During the first quarter of 2006, we assigned our contracts to supply natural gas to the Jacksonville Electric Authority and The City of Lakeland for no cash consideration. We will record a gain of approximately $50 million related to this assignment in 2006.

The following is a reconciliation of our commodity-based derivatives for the years ended December 31, 2005 and 2004:


						Other			Total
			Derivatives			Commodity-			Commodity-
			Designated			Based			Based
			as Hedges			Derivatives			Derivatives

			(In millions)
Fair value of contracts outstanding at December 31, 2003			$	(31	)	$	1,437		$	1,406

	Fair value of contract settlements during the period			49			(848	)		(799	)
	Change in fair value of contracts			38			(641	)		(603	)
	Designation of other commodity based derivatives as hedges⁽¹⁾			(592	)		592			—
	Option premiums paid⁽²⁾			—			64			64

		Net change in contracts outstanding during the period		(505	)		(833	)		(1,338	)

Fair value of contracts outstanding at December 31, 2004				(536	)		604			68

	Fair value of contract settlements during the period⁽³⁾			665			(174	)		491
	Change in fair value of contracts			(793	)		(767	)		(1,560	)
	Assignment of power contracts			—			(442	)		(442	)
	Reclassification of derivatives that no longer qualify as hedges⁽⁴⁾			11			(11	)		—
	Option premiums paid⁽²⁾			—			27			27

		Net change in contracts outstanding during the period		(117	)		(1,367	)		(1,484	)

Fair value of contracts outstanding at December 31, 2005			$	(653	)	$	(763	)	$	(1,416	)


⁽¹⁾	Represents the fair value of the contracts on the day they were designated as hedges.
⁽²⁾	Amounts are net of premiums received.
⁽³⁾	Includes derivative contracts sold in conjunction with the sales of Cedar Brakes I and II and Mohawk River Funding II and amounts paid in conjunction with the assignment of our Cordova tolling agreement. In connection with the sales of Cedar Brakes I and II and Mohawk River Funding II, we also assigned or terminated a number of our other commodity-based derivatives.
⁽⁴⁾	The loss of hedge accounting was a result of a reduction of anticipated production volumes.

Fair Value of Contract Settlements. 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.

Changes in Fair Value of 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.

Assignment of Power Contracts. In December 2005, we entered into an agreement to assign the majority of our power derivative assets to Morgan Stanley. The assignment requires the consent of existing third parties before the contracts can be transferred to Morgan Stanley. Until the assignment is finalized, we entered into offsetting liability contracts with Morgan Stanley to eliminate the commodity price risk associated with the contracts being assigned. We received total proceeds of $442 million to enter into these offsetting contracts and deposited a similar amount of cash margin. The amount we received approximated the value we would have received if we had directly sold our power derivative assets. We anticipate that this assignment will be completed in the first half of 2006.

Results of Operations

Overview

As of December 31, 2005, our operating business segments were Pipelines, Exploration and 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

corporate activities include our general and administrative functions, as well as a telecommunications business and various other contracts and assets.

Our management uses 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 cumulative effect of accounting changes, (ii) income taxes, (iii) interest and debt expense and (iv) distributions on preferred interests of consolidated affiliates. Our businesses consist of consolidated operations as well as investments in unconsolidated affiliates. We exclude interest and debt expense and distributions on preferred interests of consolidated subsidiaries from this measure so that investors may evaluate our operating results independently from our financing methods or capital structure. We believe EBIT is useful 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:


			2005			2004			2003

			(In millions)
Segment
	Pipelines		$	1,226		$	1,331		$	1,234
	Exploration and Production			696			734			1,091
	Marketing and Trading			(837	)		(539	)		(809	)
	Power			(89	)		(747	)		(165	)
	Field Services			285			84			129

		Segment EBIT		1,281			863			1,480
Corporate and other				(521	)		(217	)		(852	)

		Consolidated EBIT		760			646			628
Interest and debt expense				(1,354	)		(1,568	)		(1,768	)
Distributions on preferred interests of consolidated subsidiaries				(9	)		(25	)		(52	)
Income taxes				251			43			530

	Loss from continuing operations			(352	)		(904	)		(662	)
Discontinued operations, net of income taxes				(250	)		(43	)		(1,212	)
Cumulative effect of accounting changes, net of income taxes				(4	)		—			(9	)

	Net loss		$	(606	)	$	(947	)	$	(1,883	)

The discussions that follow provide additional analysis of the year over year results of each of our business segments, our corporate activities and other income statement items.

Pipelines Segment

Overview

Our Pipelines segment consists of interstate natural gas transmission, storage and LNG terminalling related services, primarily in the United States. We face varying degrees of competition in this segment from other existing and proposed 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 and financial results have historically been relatively stable. However, they 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 2005, 79 percent of our revenues were attributable to reservation charges paid by firm customers. Reservation charges are paid regardless of volumes transported or stored. The remaining 21 percent were 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 plant markets.

In addition, our ability to extend existing customer contracts or remarket 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 requirements, 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 contract term for active contracts is approximately five years as of December 31, 2005. Below is the expiration schedule for firm transportation contracts executed as of December 31, 2005, including those whose terms begin in 2006 or later.


			Percent of Total
	BBtu/d		Available Capacity

2006		4,437		14
2007		5,874		19
2008		2,931		9
2009 and beyond		18,406		58

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:


			2005			2004			2003

			(In millions, except volume
			amounts)
Operating revenues			$	2,783		$	2,651		$	2,647
Operating expenses				(1,764	)		(1,522	)		(1,584	)

	Operating income			1,019			1,129			1,063
Other income				207			202			171

	EBIT		$	1,226		$	1,331		$	1,234

Throughput volumes (BBtu/d)⁽¹⁾
	TGP			4,493			4,519			4,760
	EPNG and MPC			4,214			4,235			4,066
	ANR			4,100			4,067			4,232
	CIG, WIC and CPG			3,641			2,795			2,743
	SNG			1,984			2,163			2,101
	Equity investments (our ownership share)			2,833			2,798			2,433

		Total throughput		21,265			20,577			20,335


⁽¹⁾	Volumes exclude intrasegment activities.

The table below and discussion that follows detail the impact on EBIT of significant events in 2005 compared with 2004 and 2004 as compared with 2003. We have also provided an outlook on events that may affect our operations in the future.


		2005 to 2004												2004 to 2003

											EBIT												EBIT
		Revenue			Expense			Other			Impact			Revenue			Expense			Other			Impact

		Favorable/(Unfavorable)												Favorable/(Unfavorable)
		(In millions)												(In millions)
Pipeline expansions		$	82		$	(28	)	$	(2	)	$	52		$	33		$	(6	)	$	(6	)	$	21
Contract modifications/terminations/settlements			48			—			1			49			(93	)		37			—			(56	)
Gas not used in operations, revaluations, processing revenues and other natural gas sales			1			(11	)		—			(10	)		79			(19	)		—			60
Hurricanes Katrina and Rita			(13	)		(29	)		—			(42	)		—			—			—			—
General and administrative expense			—			(60	)		—			(60	)		—			(44	)		—			(44	)
Operating costs			—			(43	)		—			(43	)		—			130			—			130
Impairments of pipeline development projects			—			(46	)		—			(46	)		—			—			—			—
Other regulatory matters			—			(4	)		1			(3	)		—			(9	)		(19	)		(28	)
Equity earnings from Citrus			—			—			1			1			—			—			22			22
Mexico investments			(2	)		—			1			(1	)		9			(6	)		17			20
Other⁽¹⁾			16			(21	)		3			(2	)		(24	)		(21	)		17			(28	)

	Total impact on EBIT	$	132		$	(242	)	$	5		$	(105	)	$	4		$	62		$	31		$	97


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

Expansions

During the three years ended December 31, 2005, we completed a number of expansion projects that have generated or will generate new sources of revenues, the more significant of which were our CPG pipeline expansion, our ANR Westleg, Eastleg and Northleg Expansions, our SNG south System Expansions and our TGP South Texas Expansion. The CPG pipeline increased our revenues by $60 million and overall EBIT by $27 million during 2005 compared to 2004. Phase II of the CPG pipeline, which added 181,000 Mcf/d of capacity, was placed in service in December 2005. Overall, our expansions during this time period added approximately 3,253 MMcf/d to our overall pipeline system.

Currently, we have a number of pipeline expansion projects underway, which we are in various stages of certification and approval. The following are those expansion projects that have been approved by the FERC and that have been recently completed or are in various stages of completion:

Anticipated Completion

Estimated

Project

or In-Service Date

Cost

Estimated Future Revenues

ANR

Wisconsin 2006

November 2006

$48 million

2006 - $1 million; 2007 - $8 million;

Thereafter - $11 million annually

SNG

Elba Island LNG facility

February 2006

$157 million

$29 million annually

WIC

Piceance Basin

March 2006

$132 million

2006 - $11 million; 2007 - $19 million;

Thereafter - $21 million annually

CIG

Raton Basin

September and

$54 million

2006 - $9 million;

December 2005

Thereafter - $13 million annually

TGP

Northeast ConneXion- NY/NJ

November 2006

$39 million

2006 - $2 million;
Thereafter - $11 annually

Triple T

August 2006

$10 million⁽¹⁾

⁽²⁾

Louisiana Deepwater

October 2006

$11 million

⁽²⁾


⁽¹⁾	An additional $8 million of costs will be funded by ANR.
⁽²⁾	Revenues for these projects will be based on throughput levels as natural gas reserves are developed. We expect these revenues to commence in 2006 for the Triple T expansion and in 2007 for the Louisiana Deepwater Link expansion.

Contract Modifications/Terminations/ Settlements

During 2004, we modified, terminated, or settled several contracts on several of our pipeline systems, resulting in a $56 million reduction in EBIT compared with 2003. In 2005, these transactions improved EBIT by $49 million compared with 2004. Below is a further discussion of these significant events:


	ANR. In 2005, ANR (i) completed the restructuring of its transportation contracts with one of its shippers on its Southwest and Southeast Legs as well as a related gathering contract, which increased revenues and EBIT by $29 million in 2005 and (ii) settled two transportation agreements previously rejected in the bankruptcy of USGen New England, Inc., which increased EBIT by $15 million but will have no ongoing impact. In 2004, ANR (i) renegotiated or restructured several contracts including its contracts with We Energies, which contributed to the decrease in its revenues by $36 million in 2004 and (ii) terminated the Dakota gasification facility contract on its system, which resulted in lower operating revenues and lower operating expenses during 2004, without a significant overall impact on operating income and EBIT.

	EPNG. In 2005, EPNG benefited from the termination of the restrictions in 2004 on remarketing expiring capacity contracts, which increased revenues and EBIT by $5 million during 2005 as compared to 2004. In 2004, EPNG experienced a reduction in revenues of $24 million due to the expiration at the end of 2003 of its historical risk sharing provisions, which had provided revenues, net of a sharing obligation.

	In December 2004, Southern California Gas Company (SoCal) acquired approximately 750 MMcf/d of capacity on EPNG’s system under new contracts with various terms extending from 2009 to 2011 commencing September 2006. We have executed the relevant transportation service agreements

with SoCal. Effective September 2006, approximately 500 MMcf/d of capacity formerly held by SoCal to serve its noncore customers will be available for recontracting. We are remarketing the remaining expiring capacity to serve SoCal’s non-core customers or to serve new markets. We are also pursuing the option of using some or all of this capacity to provide new services to existing markets. At this time, we are uncertain how much of this existing capacity will be recontracted, and if so at what rates.

Gas Not Used in Operations, Revaluations, Processing Revenues 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 retain and dispose of according to our tariffs or FERC orders, relative to the amount of gas we use for operating purposes and the price of natural gas. The difference between the amount retained and the amount used in operations results in revenues or expenses to us, which are driven by volumes and prices during a given period. In addition, the timing of these revenues or expenses can vary based on each pipeline’s ability to sell or otherwise realize the value of gas not used in operations. The level of retained gas on our systems relative to amounts we use are based on factors such as system throughput, facility enhancements and the ability to operate the pipeline in the most efficient and safe manner. Additionally, several of our pipelines have encroachments against their system gas supply and net imbalances to shippers that are impacted by changing gas prices each period. In 2005, higher gas prices caused an increase in our obligation to replace system gas and settle gas imbalances in the future, resulting in an unfavorable impact on our operating results. Our pipelines also retained lower volumes of gas not used in operations during 2005. These unfavorable impacts were partially offset by the sale of higher volumes of natural gas made available by storage realignment projects in 2005 versus 2004. During 2003 and 2004, higher volumes of gas not utilized for operations and a steadily increasing natural gas price environment resulted in a favorable impact on our operating results in 2004 versus 2003. We anticipate that the overall activity in this area will continue to vary based on factors such as rate actions, some of which have already been implemented, the efficiency of our pipeline operations, natural gas prices and other factors.

Hurricanes Katrina and Rita. Hurricanes Katrina and Rita had substantial impacts on offshore producers in the Gulf of Mexico Region, resulting in the shut-in of a significant portion of offshore production in the affected areas. In August 2005, Hurricane Katrina resulted in the initial shut-in of approximately 3 Bcf/d of gas supply on our pipeline systems. Prior to Hurricane Rita in September 2005, we had approximately of 1.2 Bcf/d of natural gas supply shut-in. Hurricane Rita resulted in an incremental reduction in supply of approximately 2.9 Bcf/d on our systems. Currently, we have approximately 0.6 Bcf/d of natural gas supply shut-in on our pipeline systems. The timing of these volumes becoming available is dependent on the completion of pipeline and compressor station repairs, the ongoing evaluation of producers’ platforms upstream of our pipelines and potential processing constraints if third-party processing facilities are not available. Furthermore, these operational constraints have impacted the efficiency of our pipeline operations. The hurricanes adversely affected our EBIT in the fourth quarter of 2005 by $42 million because of their impact on certain usage revenues, estimated unreimbursed repair costs, increased operating costs and lost revenues associated with reductions in service. The adverse effect on our results may continue into early 2006.

General and Administrative Expenses During the year ended December 31, 2005, our general and administrative costs were higher than in 2004, primarily due to an increase in direct payroll related benefits for our employees of $42 million, higher legal and insurance costs of $14 million, and higher corporate overhead allocations from El Paso of $2 million. El Paso’s allocation to us increased in 2005 based on the estimated level of resources devoted to our segment’s operations and the relative size of our EBIT, gross property and payroll as compared to the consolidated totals.

Operating Costs. Over the past two years, we incurred higher costs for compressor engine repair and preventative maintenance, lowering of lines and pipeline integrity testing. Additionally, in 2005 we recorded higher legal and environmental reserves. In 2003, El Paso finalized the Western Energy settlement and EPNG recorded charges of $140 million in operating expenses related to this settlement.

Beginning in 2006, we will be required under a FERC accounting release to expense certain costs incurred in connection with our pipeline integrity programs, instead of our current practice of capitalizing them as part of our property, plant and equipment. We currently estimate that we will be required to expense

an additional amount of pipeline integrity costs under this accounting release in the range of approximately $26 million to $41 million annually.

Impairments of Pipeline Development Projects. During the fourth quarter of 2005, we discontinued a portion of our Seafarer project and the entirety of our Blue Atlantic development project due to changing market conditions.

Other Regulatory Matters. The following discussion describes certain regulatory matters that have impacted our operations or will have an impact on our operations beginning in 2006.


	In 2003, we re-applied 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 requires a company to capitalize items that will be considered in future rate proceedings. Upon re-application, we recorded $18 million in income resulting 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 annual increase in depreciation expense of approximately $9 million. 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.

	Rate Cases. Our pipeline systems periodically file for changes in their rates, which are subject to the approval of the FERC. Changes in rates and other tariff provisions resulting from these regulatory proceedings have the potential to positively or negatively impact our profitability. Currently, certain of our pipelines have no requirements to file new rate cases and expect to continue operating under their existing rates. However, certain other pipelines listed below are currently in rate proceedings or have upcoming rate actions.


	•	EPNG — Filed a rate case in June 2005 proposing an increase in revenues of 10.6 percent or $56 million over current tariff rates and also proposing new services and revisions to certain terms and conditions of existing services, including the adoption of a fuel tracking mechanism. On January 1, 2006, the rates, which are subject to refund, and the fuel tracking mechanism became effective. Additionally, settlement discussions with major customers are underway and implementation of new services is scheduled for April 1, 2006.

	•	CIG — Will be required to file for new rates to be effective in the fourth quarter of 2006.

	•	MPC — Is expected to file for new rates that would be effective March 2007.

Exploration and Production Segment

Overview

Our Exploration and Production segment conducts our natural gas and oil exploration and production activities. Our operating results in this segment 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.

We manage this business with the goal to create shareholder value through disciplined capital allocation, cost control and portfolio management. Our natural gas and oil reserve portfolio blends slower decline rate, typically longer lived assets in our Onshore region with steeper decline rate, shorter lived assets in our Texas Gulf Coast and Gulf of Mexico and south Louisiana regions. We believe the combination of our assets in these regions provides significant near-term cash flow while providing consistent opportunities for high-return investments. During the past two years, we have dedicated substantial resources and management effort to stabilizing and improving this business. We believe this effort has been largely successful. Our efforts have been focused on the following:


Goal or Strategy	Actions Taken	Results

Improve capital discipline and returns	Created a standard economic measure known as PVR (present value ratio) to evaluate project success. This ratio represents the present value of future after-tax cash flows discounted at 12% over total investment. Our target ratio is 1.15, which simply means that every $1.00 invested returns $1.15 on an after-tax, discounted basis over the life of the project. A rigorous post-spending analysis is prepared and a monthly scorecard for each operating region is evaluated by management.	Our 2005 actual post-drill PVR was 1.19 using a $4.75/MMBtu plan price compared to our pre-drill PVR target of 1.23. Our PVR was 2.11 using 2005 realized prices with the year-end strip prices thereafter.
Improve portfolio management	Allocated a greater percentage of capital expenditures to onshore exploration and development opportunities. Acquired Medicine Bow to expand our presence in the Rockies and east Texas and GMT Energy Corporation to expand our presence in east Texas. Divested certain high cost onshore and offshore properties with high abandonment liabilities and only 25 Bcfe of proved reserves. Implemented a consistent risk analysis process and reduced capital exposure to deep drilling. Utilized comprehensive mapping with life-of-property exploitation plans.	Our onshore reserves increased from 55 percent of our total reserves at year end 2004 to 60 percent of our total reserves at year end 2005. Our unconventional coal seam reserves comprise approximately one third of our total reserve base. These longer-life reserves form a stable production base and should make our business more predictable. The Medicine Bow acquisition accelerated the changes in our portfolio since over 80 percent of the proved reserves overlap with our core onshore areas.
Improve our production mix	Increased our onshore production through drilling activities and our acquisition program, including the acquisition of our equity investment in Four Star.	From 2004 to 2005, total onshore production grew as a percentage of total production. A substantial portion of the increase was organic growth as opposed to acquisitions.
Grow our reserves base	Created a balanced acquisition and drilling program that focused on increasing long life reserves while converting proved undeveloped reserves (PUD) to producing developed reserves.	During 2005, we produced 271 Bcfe (excluding our equity share of Four Star production of 9 Bcfe) while our drilling and acquisition programs generated net additions of 505 Bcfe (excluding our equity share of Four Star of 262 Bcfe). We also increased our reserves over production ratio from 7.2 years to 8.9 years. In 2005, we developed 22 percent of our total 2004 year-end PUD reserves.


Goal or Strategy	Actions Taken	Results

Build an inventory of attractive lower risk drilling prospects	Improved our ability to grow by creating a regional structure that leverages a strong acreage position in key producing basins. Utilized detailed mapping and reservoir analysis and a standardized risk measurement system to identify drilling and workover or recompletion opportunities. Completed $1.1 billion of acquisitions that complement our existing core operations.	Identified 629 wells to be drilled in 2006 with 2,620 more in future years at a $5.50/MMBtu price forecast for natural gas that generates a PVR of 1.15 or greater. Created a balanced inventory along the entire risk spectrum with low risk development prospects coupled with high potential offshore exploration and international oil opportunities.

Significant Operational Factors Affecting the Year Ended December 31, 2005


	•	Higher realized prices. We benefited from a strong commodity pricing environment in 2005. Realized natural gas prices, which include the impact of our hedges, increased 10 percent while oil, condensate and NGL prices increased 32 percent compared to 2004.

	•	Average daily production of 743 MMcfe/d (excluding 24 MMcfe/d from our equity investment in Four Star). Our average daily equivalent production decreased from 2004 primarily due to several hurricanes in the Gulf of Mexico, which caused us to shut in significant volumes in our Gulf of Mexico and south Louisiana region. We have continued to increase production volumes in our Onshore region as a result of our successful drilling and acquisition programs. However, production volumes in our Gulf of Mexico and south Louisiana region, adjusted for the impact of hurricanes, and Texas Gulf Coast region continued to gradually decrease as drilling programs and overall lower capital spending in those areas have not been sufficient to offset the historically steep production decline rates in these regions.

	•	Impact of hurricanes on production volumes. The Gulf Coast hurricanes negatively impacted our annual production by approximately 12 Bcfe or 34 MMcfe/d during 2005. Prior to Hurricane Katrina in late August 2005, our production from the Gulf of Mexico was about 205 MMcfe/d. A substantial portion of our shut-in production from Hurricane Katrina was brought back online during September 2005 to a level of about 170 MMcfe/d just prior to Hurricane Rita. We continue to experience substantial shut-in volumes from Hurricane Rita; however, Gulf of Mexico production levels have returned to approximately 130 MMcfe/d at December 31, 2005 and currently remain at that level. We expect the majority of the remaining operated Gulf of Mexico production to come back online during the first half of 2006. Also impacted were our onshore Texas Gulf Coast and Arklatex areas, where damage from Hurricane Rita initially impacted approximately 60 MMcfe/d of production. However, production was restored within a few days of the event.

	•	Drilling results. In 2005, we participated in drilling a total of 483 gross wells with a 99 percent success rate and a PVR of 1.19 based on a plan price of $4.75/MMBtu. Our drilling results by region were as follows:

Onshore region. We experienced a 99 percent success rate on 454 gross wells drilled during 2005, resulting in production growth in the Rockies, Raton, north Louisiana and Arkoma operating areas.

Texas Gulf Coast region. We experienced significant improvement in the second half of the year achieving an 89 percent success rate on 18 gross wells drilled during 2005. New Wilcox production was established from exploration at the Renger Field in Lavaca County, Texas. In addition, the shallow Vicksburg development program in Starr and Hidalgo Counties, Texas provided consistent results adding production on existing base properties.

Gulf of Mexico and south Louisiana region. Overall, we experienced a 73 percent success rate on 11 gross wells drilled during 2005. During the year, we announced our participation in two deep shelf discovery wells at West Cameron Blocks 75 and 62 in the Gulf of Mexico. These projects are expected to come on line during the first quarter of 2006 and produce 20 MMcfe/d or higher, net

to our interest. We also participated in a third discovery in 2005 through a 25 percent working interest in a well drilled at Long Point in Vermillion Parish, Louisiana, which tested at over 40 MMcfe/d, and is expected to come on line during the second quarter 2006.

Outlook for 2006

For 2006, we also expect:


	•	Capital expenditures of approximately $1 billion, excluding acquisitions;

	•	Average daily production volumes for the year of approximately 755 MMcfe/d to 780 MMcfe/d, which excludes approximately 70 MMcfe/d from our equity interest in Four Star. Our daily production volumes in Brazil averaged approximately 53 MMcfe/d during 2005. Our Brazilian production was reduced by about 30 MMcfe/d in February 2006 due to a contractual decrease in our interest from 79 percent to 35 percent in UnoPaso’s production in Brazil as a result of achieving payout;

	•	Average cash operating costs of approximately $1.64/Mcfe to $1.71/Mcfe for the year;

	•	Domestic unit of production depletion rate of $2.22/Mcfe in the first quarter of 2006. This compares to $2.16/Mcfe in the fourth quarter of 2005. The increase is expected due to higher finding and development costs and the costs of acquired reserves;

	•	Brazilian unit of production depletion rate of $1.96/ Mcfe in the first quarter of 2006. This compares to $2.39/ Mcfe in the fourth quarter of 2005; and

	•	Significant industry-wide increases in drilling and oilfield service costs that will require constant monitoring of capital spending programs and a mitigation effort designed to manage and improve field efficiency.

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 associated with our capital investment programs. Our Marketing and Trading segment has also entered into other derivative contracts that are designed to provide price protection to the overall company, which is discussed further in that segment’s operating results. Our hedging positions are regularly monitored by senior management and a committee of the Board of Directors. Because this strategy only partially reduces our exposure to downward movements in commodity prices, our reported results of operations, financial position and cash flows can be impacted significantly by movements in commodity prices from period to period. Adjustments to our hedging strategy and the decision to enter into new positions or to alter existing positions are made at the corporate level based on the goals of the overall company.

During 2005, we experienced a significant decrease in the fair value of our hedging derivatives. These fair value decreases were generally deferred in our accumulated other comprehensive income and will be recognized in our income at the time the production volumes to which they relate are sold. As of December 31, 2005, the fair value of the positions deferred in accumulated other comprehensive income was a pretax loss of $492 million. This deferred amount will be recognized in income upon the settlement of these derivative commodity instruments, but will be substantially offset by the impact of the corresponding change in the price to be received when the hedged natural gas production is sold. This will result in a realized price that is approximately equal to the hedged price if settled as originally anticipated.

Below are the hedging positions on our anticipated natural gas and oil production as of December 31, 2005:

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)

2006⁽¹⁾		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		1,142	$	3.35		1,142	$	3.35		1,155	$	3.49		1,155	$	3.49		4,594	$	3.42
2009 to 2012																		16,026	$	3.74

⁽¹⁾

The hedged natural gas prices in the table represent the price on the hedge contract when it was entered into or the price on the day it was designated as a hedge. The average cash prices to be received under these hedge contracts when they settle is approximately $3.95 per MMBtu for each of the quarters ended March 31, June 30, September 30 and December 31, 2006 and the year ended December 31, 2006.

Oil. We also have derivative contracts on our Brazilian oil production that provide us with a fixed price of $35.15 per Bbl on approximately 96 MBbls per quarter in 2006 and approximately 48 MBbls per quarter in 2007. Our 2007 derivative positions are accounted for as hedges and will be recognized in income as the positions settle, while changes in the fair value of the 2006 positions will be recognized in income as market prices change.

Operating Results

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


			2005			2004			2003

			(In millions, except volumes and prices)
Operating Revenues:
	Natural gas		$	1,420		$	1,428		$	1,831
	Oil, condensate and NGL			371			305			305
	Other			(4	)		2			5

		Total operating revenues		1,787			1,735			2,141
Transportation and net product costs⁽¹⁾				(47	)		(54	)		(82	)

		Total operating margin		1,740			1,681			2,059

Operating Expenses:
	Depreciation, depletion and amortization			(612	)		(548	)		(576	)
	Production costs⁽²⁾			(261	)		(210	)		(229	)
	General and administrative expenses			(185	)		(173	)		(160	)
	Other			(11	)		(24	)		(21	)

		Total operating expenses⁽¹⁾		(1,069	)		(955	)		(986	)

	Operating income			671			726			1,073
Other income⁽⁴⁾				25			8			18

	EBIT		$	696		$	734		$	1,091


						Percent					Percent
				2005		Variance			2004		Variance			2003

Consolidated volumes, prices and costs per unit:
	Natural gas
		Volumes (MMcf)			222,292		(9	)%		244,857		(28	)%		338,762
		Average realized prices including hedges ($/Mcf)⁽³⁾		$	6.39		10	%	$	5.83		8	%	$	5.40
		Average realized prices excluding hedges ($/Mcf)⁽³⁾		$	7.53		28	%	$	5.90		7	%	$	5.51
		Average transportation costs ($/Mcf)		$	0.18		6	%	$	0.17		(6	)%	$	0.18
	Oil, condensate and NGL
		Volumes (MBbls)			8,136		(8	)%		8,818		(25	)%		11,778
		Average realized prices including hedges ($/Bbl)⁽³⁾		$	45.60		32	%	$	34.61		33	%	$	25.96
		Average realized prices excluding hedges ($/Bbl)⁽³⁾		$	46.43		34	%	$	34.75		30	%	$	26.64
		Average transportation costs ($/Bbl)		$	0.63		(44	)%	$	1.12		7	%	$	1.05
	Total equivalent volumes (MMcfe)				271,107		(9	)%		297,766		(27	)%		409,432
	Production costs ($/Mcfe)
		Average lease operating costs		$	0.72		20	%	$	0.60		43	%	$	0.42
		Average production taxes			0.24		118	%		0.11		(21	)%		0.14

			Total production cost⁽²⁾	$	0.96		35	%	$	0.71		27	%	$	0.56

	Average general and administrative cost ($/Mcfe)			$	0.68		17	%	$	0.58		49	%	$	0.39
	Unit of production depletion cost ($/Mcfe)			$	2.10		24	%	$	1.69		29	%	$	1.31
Unconsolidated affiliate volumes (Four Star)⁽⁴⁾
	Natural gas (MMcf)				6,689
	Oil, condensate and NGL (MBbls)				359
	Total equivalent volumes (MMcfe)				8,844


⁽¹⁾	Transportation and net product costs are included in operating expenses on our consolidated statement of income.
⁽²⁾	Production costs include lease operating costs and production related taxes (including ad valorem and severance taxes).
⁽³⁾	Prices are stated before transportation costs.
⁽⁴⁾	Includes equity earnings and volumes for our investment in Four Star. Our equity interest in Four Star was acquired in connection with our acquisition of Medicine Bow in August 2005.


	Year Ended December 31, 2005 Compared to Year Ended December 31, 2004

Our EBIT for 2005 decreased $38 million as compared to 2004. The table below lists the significant variances in our operating results in 2005 as compared to 2004:


			Variance

			Operating			Operating
			Revenue			Expense			Other			EBIT

			Favorable/(Unfavorable)
			(In millions)
Natural Gas Revenue
	Higher realized prices in 2005		$	362		$	—		$	—		$	362
	Lower volumes in 2005			(133	)		—			—			(133	)
	Impact of hedges			(237	)		—			—			(237	)
Oil, Condensate and NGL Revenue
	Higher realized prices in 2005			95			—			—			95
	Lower volumes in 2005			(24	)		—			—			(24	)
	Impact of hedges			(5	)		—			—			(5	)
Depreciation, Depletion and Amortization Expense
	Higher depletion rate in 2005			—			(110	)		—			(110	)
	Lower production volumes in 2005			—			45			—			45
Production Costs
	Higher lease operating costs in 2005			—			(17	)		—			(17	)
	Higher production taxes in 2005			—			(34	)		—			(34	)
General and Administrative Expenses				—			(12	)		—			(12	)
Other
	Earnings from investment in Four Star			—			—			19			19
	Other			(6	)		14			5	⁽¹⁾		13

		Total Variances	$	52		$	(114	)	$	24		$	(38	)


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

Operating revenues. During 2005, we continued to benefit from a strong commodity pricing environment for natural gas and oil, condensate and NGL. However, losses in our hedging program for the year ended December 31, 2005 were $260 million compared to $18 million in 2004. Additionally, we experienced a nine percent decrease in production volumes versus the same period in 2004. Although our production volumes benefited from the acquisitions in 2005 and our acquisition and consolidation of the remaining interest in UnoPaso in Brazil in July 2004, our Texas Gulf Coast and Gulf of Mexico and south Louisiana regions experienced declines in year over year production due to normal declines and a lower capital spending program in these areas over the last several years. In addition, the Gulf of Mexico and south Louisiana region was impacted by the hurricanes discussed previously, while the Texas Gulf Coast region was impacted by mechanical well failures.

Depreciation, depletion and amortization expense. During 2005, we experienced higher depletion rates compared to 2004 as a result of higher finding and development costs and the cost of acquired reserves which resulted in higher depreciation, depletion and amortization expense. However, during 2005, the impact of lower production volumes partially offset the impact of our higher depletion rates.

Production costs. We continued to experience higher costs in 2005 due to the implementation of programs in the first half of 2005 to improve production in the Texas Gulf Coast and Gulf of Mexico and south Louisiana regions, higher salt water disposal costs, utility expenses, marine transportation costs and increased operating costs in Brazil due to our July 2004 UnoPaso acquisition and consolidation. Production taxes were also higher as the result of higher commodity prices in 2005 and higher tax credits taken in 2004 on high cost natural gas wells.

General and administrative expenses. Our general and administrative expenses were higher in 2005 than in 2004, primarily due to an increase in direct payroll related benefits for our employees, and higher legal and insurance costs.

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

Our EBIT for 2004 decreased $357 million as compared to 2003. The table below lists the significant variances in our operating results in 2004 as compared to 2003:


			Variance

			Operating			Operating
			Revenue			Expense			Other⁽¹⁾		EBIT

			Favorable/(Unfavorable)
			(In millions)
Natural Gas Revenue
	Lower volumes in 2004		$	(518	)	$	—		$	—	$	(518	)
	Higher realized prices in 2004			96			—			—		96
	Impact of hedges			19			—			—		19
Oil, Condensate and NGL Revenue
	Lower volumes in 2004			(79	)		—			—		(79	)
	Higher realized prices in 2004			72			—			—		72
	Impact of hedges			7			—			—		7
Depreciation, Depletion and Amortization Expense
	Lower production volumes in 2004			—			146			—		146
	Higher depletion rate in 2004			—			(115	)		—		(115	)
Production Costs
	Higher lease operating costs in 2004			—			(8	)		—		(8	)
	Lower production taxes in 2004			—			27			—		27
General and Administrative Expenses				—			(13	)		—		(13	)
Other				(3	)		(6	)		18		9

		Total Variances	$	(406	)	$	31		$	18	$	(357	)


⁽¹⁾	Other consists of changes in transportation costs and other income.

Operating Revenues. During 2004, we experienced a significant decrease in production volumes. The decline in our natural gas volumes was due to normal production declines in the Texas Gulf Coast and Gulf of Mexico and south Louisiana regions, asset sales, 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 in 2004 as a result of our acquisition of the remaining interest and consolidation of UnoPaso. In addition, we encountered 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 production declines 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 gross workover costs due to the implementation of programs in the second half of 2004 to improve production in the Texas Gulf Coast and Gulf of Mexico and south Louisiana regions. We also incurred higher utility expenses and higher salt water disposal costs in the Onshore region. However, 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.

General and administrative expenses. Higher contract labor costs and lower capitalized costs were the main factors leading to the increase in general and administrative expenses in 2004.

Marketing and Trading Segment

Our Marketing and Trading segment’s primary focus is to market our Exploration and Production segment’s natural gas and oil production and to manage the company’s overall price risks, primarily through the use of natural gas and oil derivative contracts. Historically this segment has also managed a portfolio of power derivatives and contracts, as well as other structured commodity-based transactions. In the fourth quarter of 2005, we entered into transactions to assign a majority of our power contracts to third parties, including our Cordova tolling agreement.

The following is a summary of our remaining contracts and their sensitivity to changes in commodity prices as of December 31, 2005:


				Expected
				Earnings
Contract Type		Description	Status	Volatility

Mark-to-Market
	Production-related natural gas and oil derivatives	Option contracts with various floor and ceiling prices; fixed-for-float swaps.	Significantly impacted our results in 2005 due to changes in natural gas and oil prices and may continue to do so if volatility continues in the future.		High
	Power	PJM basis positions.	Impacted by changes in regional power prices in 2005 and may continue to be impacted if volatility continues.		Moderate
		Power supply contracts.	Entered into positions in December 2005 to substantially eliminate price risk associated with these contracts.		Low
	Other natural gas	Fixed-price, physical delivery contracts; fixed-for-float swaps.	Terminated or assigned a significant number of contracts in recent years and anticipate additional assignments in 2006, which will result in further reduction in exposure.		Low
Accrual
	Transportation-related	Pipeline capacity contracts.	Experienced significant losses historically due to regional changes in natural gas prices. Significant expirations in 2006 and 2015 will reduce our exposure.		Low
	Long-term gas supply obligations	Supply contracts with delivery obligations up to 1 Bcf/d.	Approximately 90 percent of obligations are index-priced and remaining fixed price obligations are hedged.		Low

While we continue to evaluate potential opportunities to assign or otherwise divest of contracts related to our legacy trading operations, we may not liquidate certain of these remaining transactions before their expiration if (i) they are either uneconomical to sell or terminate in the current environment due to their terms, credit concerns of the counterparty or lack of liquidity in the market or (ii) a sale would require an acceleration of cash demands. Any future liquidations may impact our cash flows and financial results. The

discussion that follows provides additional analysis of the contracts held by our Marketing and Trading segment.

Production-related Natural Gas and Oil Derivatives

During 2004 and 2005, we entered into option contracts that provide El Paso with various floor and ceiling prices on a portion of its anticipated natural gas production in 2006 through 2009 and oil production in 2007 and 2008. We paid a total premium of $144 million for our floors and received a $50 million premium for our ceilings. We also maintain swaps that obligate us to sell natural gas and oil at fixed prices. As of December 31, 2005, our contracts were as follows:


	Swaps⁽¹⁾				Floors⁽¹⁾				Ceilings⁽¹⁾

			Average				Average				Average
	Volumes		Price		Volumes		Price		Volumes		Price
Natural Gas
2006		25	$	8.11		120	$	7.00		60	$	9.50
2007		—		—		51	$	6.41		21	$	9.00
2008		—		—		18	$	6.00		18	$	10.00
2009		—		—		17	$	6.00		17	$	8.75
Oil
2006		1,044	$	58.81		—		—		—		—
2007		—		—		1,009	$	55.00		1,009	$	60.38
2008		—		—		930	$	55.00		930	$	57.03


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

For a combined discussion of the cash prices under these contracts and contracts held by our Exploration and Production segment, see Liquidity discussion on page 28.

Contracts Related to Legacy Trading Operations

Natural gas contracts. These contracts primarily relate to our transportation activities. Specifically, these contracts provide us with approximately 1.5 Bcf of pipeline capacity per day, on which we will be charged approximately $140 million in annual demand charges in 2006 and, on average, $111 million in each of the years 2007 through 2010. The recovery of these charges, and therefore the profitability of these contracts, is dependent upon our ability to use the contracted pipeline capacity, which is impacted by a number of factors including differences in natural gas prices at contractual receipt and delivery locations, the working capital needed to use this capacity and the capacity required to meet our other long term obligations. These transportation contracts are accrual-based and impact our gross margin as delivery or service under the contracts occurs.

In addition to these transportation-related contracts, we have other contracts with third parties that require us to purchase or deliver natural gas primarily at market prices. Our remaining long-term contracts require us to sell natural gas to various power plants and have expiration dates ranging from 2009 to 2028.

During the first quarter of 2006, we assigned our contracts to supply natural gas to the Jacksonville Electric Authority and The City of Lakeland, Florida for no cash consideration. We will record a gain of approximately $50 million related to this assignment in 2006.

Power Contracts. As of December 31, 2005, our primary remaining exposure in our power portfolio is for locational differences in power prices between eastern PJM and the west PJM hub through 2016.

We have several contracts that obligate us to deliver power or manage the risk associated with our obligations to deliver power, including those related to UCF. In December 2005, we entered into contracts to substantially offset the price risk associated with these power supply and power price risk management contracts. We will assign or terminate a portion of these contracts in 2006; however, we will retain some

contracts (including those related to UCF) that will present minimal price risk to us in the future as any exposure is largely offset by the new contracts we entered into in December 2005.

Operating Results

As a result of substantial changes in the composition of our portfolio over the past three years, year-to-year comparability in our operating results was affected. The tables below and the discussion that follows provide the overall operating results and analysis for our Marketing and Trading segment and factors by significant contract type that affected the profitability of our Marketing and Trading segment during each of the three years ended December 31:


			2005			2004			2003

			(In millions)
Overall EBIT:
	Gross margin⁽¹⁾		$	(796	)	$	(508	)	$	(636	)
	Operating expenses			(59	)		(54	)		(183	)

		Operating loss		(855	)		(562	)		(819	)
	Other income, net			18			23			10

		EBIT	$	(837	)	$	(539	)	$	(809	)


						2005			2004			2003

						(In millions)
Gross Margin by Significant Contract Type:
Production-Related Natural Gas and Oil Derivatives
		Changes in fair value of options and swaps				$	(436	)	$	53		$	—
		Changes in fair value of other derivatives					—			(439	)		(425	)

			Gross margin				(436	)		(386	)		(425	)
Contracts Related to Legacy Trading Operations
	Natural gas contracts:
		Transportation-related contracts:
			Demand charges				(156	)		(151	)		(177	)
			Settlements⁽²⁾				121			87			18
		Changes in fair value of other natural gas derivative contracts					39			44			(6	)
	Power contracts:
		Changes in fair value of Cordova tolling agreement					(136	)		(36	)		75
		Change in fair value of other power derivatives					(250	)		(85	)		(96	)
		Other					22			19			(25	)

				Gross margin			(360	)		(122	)		(211	)

					Total gross margin	$	(796	)	$	(508	)	$	(636	)


⁽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.

⁽²⁾	Includes a $50 million gain in 2004 related to the early termination of an LNG contract and a $17 million loss in 2003 related to the early termination of a storage contract.

Production-related Natural Gas and Oil Derivative Contracts

Options and swaps. The fair value of our production-related option and swap contracts declined in 2005 due to increases in natural gas and oil prices, and as a result, we experienced significant losses. If natural gas

and oil prices remain above the floor prices of our option contracts, these contracts will remain unexercised and will expire without any value. For our ceiling contracts, if natural gas and oil prices continue to increase, further losses will occur since we are obligated under these contracts to provide natural gas and oil at fixed prices that are currently lower than the market price.

Other production-related derivatives. In 2004 and 2003, our losses were a result of increases in natural gas prices relative to fixed priced commodity contracts held at the time. In the fourth quarter of 2004, we designated those contracts as accounting hedges and transferred them to our Exploration and Production segment. As a result, the income impacts of those contracts are now reflected in our Exploration and Production segment results.

Contracts Related to Legacy Trading Operations


	Natural Gas Contracts

Transportation-related contracts. During 2005, our ability to use our transportation-related contracts improved due to increased price differentials between the receipt and delivery points for these contracts. The following table is a summary of our demand charges (in millions) and our percentage of recovery of these charges for each of the three years ended December 31:


		2005			2004			2003

Alliance:
	Demand charges	$	65		$	61		$	56
	Recovery		93	%		72	%		74	%
Enterprise Texas:
	Demand charges	$	26		$	27		$	23
	Recovery		8	%		2	%		—	⁽¹⁾
Other:
	Demand charges⁽²⁾	$	65		$	63		$	98
	Recovery		94	%		38	%		8	%


⁽¹⁾	In 2003, we were unable to recover demand charges and incurred $13 million in losses in excess of the demand charges related to managing the capacity under these contracts.

⁽²⁾	Includes demand charges related to storage contracts of $1 million, $2 million, and $21 million in 2005, 2004, and 2003.

Other natural gas derivative contracts. Our exposure to the volatility of gas prices as it relates to our other natural gas derivative contracts varies from period to period based on whether we purchase more or less natural gas than we sell under these contracts. Because we had the right to purchase more natural gas at fixed prices than we had the obligation to sell under these contracts during 2003, 2004 and 2005, the fair value of these contracts increased as natural gas prices increased during those years. However, the increase in 2003 was more than offset by losses associated with the early termination of a number of these contracts resulting in an overall loss for the year.

Under certain of these contracts, we supply gas to power plants that we partially own, including the Midland Cogeneration Venture(MCV) and Berkshire power projects. Due to their affiliated nature, we do not recognize mark-to-market gains or losses on these contracts to the extent of our ownership interest. However, should we sell our interests in these plants, we would record the cumulative unrecognized mark-to-market losses on these contracts, which totaled approximately $146 million as of December 31, 2005.


	Power Contracts

During 2005, we divested or entered into transactions to divest of a substantial portion of our power contracts, including our (i) Cordova tolling agreement, (ii) substantially all contracts in our power portfolio and (iii) certain other contracts related to our Power segment’s historical power contract restructuring

business. The discussion that follows details significant factors impacting our power contracts during 2005, 2004 and 2003.

Cordova tolling agreement. In the fourth quarter of 2005, we completed the assignment of this agreement to Constellation. Prior to this assignment, we experienced significant volatility under this agreement, which was sensitive to changes in forecasted natural gas and power prices. During 2004 and 2005 forecasted natural gas prices increased relative to power prices, resulting in a decrease in the fair value of the contract. However, during 2003, forecasted power prices increased relative to natural gas prices, resulting in a significant increase in the fair value of this contract.

Other power derivatives. Historically, many of our contract origination activities related to power contracts. However, in 2003, we began exiting our power contract origination activities due to changes in the energy trading environment and re-aligning the focus of our Marketing and Trading segment. Our activity in this area was as follows:


	•	During 2005, 2004 and 2003, we supplied power to Morgan Stanley under a power supply agreement related to our formerly-owned UCF entity. We were also required to purchase power under a number of other power agreements, which included those used to manage our risk on the power supply obligation to Morgan Stanley. As a result of increasing power prices and increases in the differences in power prices at various locations in PJM, our Morgan Stanley contract decreased in fair value by $345 million, $72 million and $77 million in 2005, 2004 and 2003. These decreases were partially offset by increases in the fair value of our power purchase contacts of $223 million, $81 million and $48 million in 2005, 2004 and 2003.

In addition to our Cordova assignment, we entered into an agreement in December 2005 to assign the majority of our remaining power portfolio to Morgan Stanley. This assignment includes all of our remaining power derivative assets, except for certain positions in the PJM power pool that we will retain. The assignment requires consents by the current counterparties to the contracts. Until the assignment is finalized, we entered into new offsetting liability contracts with Morgan Stanley for the power portfolio being assigned, which eliminated our cash and earnings exposure to power price movements for these contracts. We received total proceeds of $442 million to enter into these offsetting contracts and deposited a similar amount of cash margin. The amount we received approximated the value we would have received if we had directly sold our power derivative assets.


	•	Contracts related to our former power contract restructuring activities. During the first quarter of 2005, we assigned our contracts to supply power to our Power segment’s Cedar Brakes I and II entities to Constellation. We recorded a loss of $30 million in 2004 related to entering into an agreement to assign these contracts. In 2004 and 2003, these contracts decreased in fair value by $64 million and $67 million. In conjunction with the assignment, we also entered into derivative contracts with Constellation that swap the locational differences in power prices at several power plants in eastern PJM and the west PJM hub through 2013. Due to unfavorable changes in the power prices at each location, the fair value of these swaps decreased by $105 million during 2005.

During the fourth quarter of 2005, we assigned our contracts to supply power to our Power segment’s Mohawk River Funding II subsidiary to Merrill Lynch. We recognized a loss of $23 million associated with this assignment. As a result of this assignment, we have no further obligations to provide power to our Power segment.

Other. During 2005, a bankruptcy court entered an order allowing Mohawk River Funding III’s (MRF III) bankruptcy claims with USGen New England. We received payment on this claim and recognized a gain of $17 million in 2005 related to this settlement. During 2004, we recorded a $25 million gain related to the termination of a power contract with our Power segment, which was eliminated in El Paso’s consolidated results.

Operating Expenses

During 2005, our Marketing and Trading segment recorded $18 million of legal settlements and reserves, which resulted in increased operating expenses. However, this amount was partially offset by a decline in general and administrative expenses. Overall operating expenses have decreased significantly from 2003 due primarily to the following:


	•	Recording $26 million of charges in operating expenses in 2003 related to the Western Energy Settlement prior to the transfer of this obligation to our corporate operations.

	•	Recording bad debt expense associated with a fuel supply agreement we have with the Berkshire power plant of $2 million, $10 million and $28 million in 2005, 2004 and 2003.

	•	Incurring lower corporate overhead allocation and general and administrative expenses based on overall cost reduction efforts at the corporate level and our reduced level of operations in 2004 and 2005. These reductions were primarily due to a reduction of our trading activities coupled with the closing of our office in London in 2003.

Power Segment

As of December 31, 2005, our Power segment primarily consisted of international power assets in Brazil. In March 2006, our Board of Directors approved the sale of our interest in the Macae power plant in Brazil, which we sold in April 2006. As a result, we reflected the financial results of Macae as discontinued operations for all periods presented. Substantially all of our other international power assets, primarily in Asia and Central America, are under sales agreements and are expected to close in the first half of 2006. Over the past several years, we also had substantial domestic power operations, including a portfolio of domestic power plants and a power contract restructuring business. Substantially all of these domestic operations have been sold or fully impaired.

As of December 31, 2005, the total financial exposure on our investments in Brazil, excluding Macae, was approximately $716 million. Based on the status of negotiations and disputes in certain of these projects, it is possible that additional impairments of these assets may occur in the future. Below is a further discussion of these matters, which are further described in Financial Statements and Supplementary Data, Note 16.


	•	Porto Velho. The 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 energy and capacity sold by the plant, provided that the plant operates within certain operational requirements. As a result, the profitability of the plant is dependent primarily on meeting the operational requirements of the contract and through efficient operations and maintenance practices. In October 2004, our Porto Velho project experienced an outage with its steam turbine, which resulted in a partial reduction in the plant’s capacity. The project expects to have the steam turbine back in service in the first quarter of 2006. In addition, the project is also currently negotiating certain provisions of its power purchase agreement and the outcome of these negotiations may impact the future financial performance of the project.

	•	Manaus and Rio Negro. In January 2005, we signed new power sales contracts for our Manaus and Rio Negro power plants with Manaus Energia. Under these new contracts, Manaus Energia will pay a price for its power that is similar to that in the previous contracts. In addition, Manaus Energia will assume ownership of the plants in 2008.

	•	Other. At our Araucaria power plant, the power sales contract is currently in international arbitration due to non-payment by the utility that purchases power from the plant. In early 2006, we signed a letter of intent to resolve the arbitration proceedings and to sell our investment in Araucaria to COPEL for $190 million. We also have an interest in two pipelines which reached full capacity in 2003 and currently generate income through the transportation of natural gas to various customers in South America.

Operating Results

The tables below and discussions that follow provide the operating results and additional analysis of our Power segment operations for the years ended December 31:


				2005			2004			2003

				(In millions)
Overall EBIT:
	Gross margin⁽¹⁾			$	63		$	274		$	572
	Operating expenses				(126	)		(836	)		(710	)

			Operating loss		(63	)		(562	)		(138	)
	Losses from unconsolidated affiliates				(139	)		(249	)		(91	)
	Other income				113			64			64

		EBIT		$	(89	)	$	(747	)	$	(165	)

EBIT by Area:
Brazil
	Impairments
		Manaus and Rio Negro		$	—		$	(183	)	$	—
	EBIT from operations				55			64			52
Other International Power
	Asia
		Impairments related to anticipated sales			(87	)		(182	)		—
		Gain on sale of KIECO, PPN and Chinese plants			131			—			—
		EBIT from operations			15			64			47
	Central and other South America
		Impairments related to anticipated sales			(89	)		—			—
		Gain on sale of Argentina			—			—			28
		EBIT from operations			5			1			8
	EBIT from other international plants and investments				14			(1	)		24
Domestic Power
	Midland Cogeneration Venture				(162	)		(171	)		29
	Other impairments, net⁽²⁾
			Sale of interest in Cedar Brakes I and II and UCF and related power restructuring contracts		—			(324	)		(15	)
			Decline in value of Chaparral investment		—			—			(207	)
			Milford receivable write-off due to lender dispute		—			—			(88	)
			Other domestic plants and investments		(5	)		(105	)		(208	)
	Proceeds from portion of MRF III bankruptcy claim previously written off				53			—			—
	EBIT from operations				—			143			256
Other⁽³⁾					(19	)		(53	)		(91	)

	EBIT			$	(89	)	$	(747	)	$	(165	)


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


⁽²⁾	Includes impairment charges and gains (losses) on the sales of assets and investments.
⁽³⁾	Includes impairments and losses on the sales of power turbines of $27 million, $1 million and $33 million in 2005, 2004 and 2003. Also includes $40 million of gains on the sales of cost basis investments in 2005.

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 2004 and 2005 were impacted significantly by regional economic and political conditions, which affected the renegotiation of several of the power contracts for our Brazilian power plants including those related to Manaus and Rio Negro.

Porto Velho. EBIT from our Porto Velho plant’s operations was $23 million, $28 million and $28 million in 2005, 2004 and 2003. The decrease in 2005 was due to the equipment failure discussed earlier that temporarily reduced the output of the plant by approximately 30 percent. This equipment failure is expected to be repaired in the first quarter of 2006.

Manaus and Rio Negro. At our Manaus and Rio Negro facilities we began negotiating new power contracts in 2003, which were to expire in 2005 and 2006. These negotiations were negatively impacted by changes in the Brazilian political environment, and as a result, we recorded an impairment on these investments in 2004. As a result of new contracts entered into during the first quarter of 2005, we deconsolidated these plants and now account for them as equity investments. The new contracts also resulted in a decrease in earnings from these projects. The Manaus and Rio Negro plants had earnings from plant operations of $19 million in 2005, $30 million in 2004 and $12 million in 2003.

South American Pipelines. The EBIT for our Brazilian operations includes EBIT earned by our Bolivia to Brazil and Argentina to Chile pipelines. EBIT was $26 million in 2005, $28 million in 2004 and $18 million in 2003. EBIT increased from 2003 to 2004 due primarily to the Bolivia to Brazil pipeline reaching full operational capacity in the third quarter of 2003.

Other International Power

During 2005 and 2004, we recorded substantial gains and losses in our other international power operations primarily based on the sale of, or the decision to sell our Asian and Central American assets. These assets have been written down to the value expected to be realized upon the close of the sales. As of December 31, 2005, the total financial exposure on our investments in Asia and Central America was approximately $377 million. Until these sales close, which we expect in the first half of 2006, we have potential risk for negative impacts of operational, economic or political events that may occur.

Prior to the decision to sell these assets, our earnings in these areas were relatively stable as the underlying plants maintained steady levels of availability and production. However, our earnings from our Asian power assets decreased in 2005 as we did not recognize approximately $30 million of earnings in Asia because we did not believe these amounts could be realized.

Domestic Power

From 2003 to 2005, we sold substantially all of our domestic power assets, including all of our remaining restructured power contracts. In conjunction with these sales, we recorded significant impairments in our domestic power business and had substantially lower earnings in our domestic power plant operations during this three year period. The discussion that follows outlines the significant events that affected our domestic operating results during the period from 2003 to 2005.


	•	MCV. As of December 31, 2005, we maintain an equity ownership in a natural gas-fired power plant, MCV. Although the price of electricity sold by MCV is indexed to coal, the plant is fueled by natural gas, which it purchases under both long-term contracts and on the spot market. Due to significant increases in natural gas prices, the economic performance of the facility was greatly impacted. In 2004, we impaired our investment in MCV by $161 million based on a decline in the value of the investment


		due to the increase in fuel costs. In 2005, we recorded our proportionate share of losses on MCV based on MCV’s impairment of the plant assets. These impairments and recorded losses reduced our net investment in the plant to zero at December 31, 2005. MCV’s owners are pursuing various commercial alternatives, which could result in the recovery of some of our previously impaired investment.

	•	Other Impairments and EBIT from Operations. Prior to 2003, Chaparral Investors, L.L.C. owned interests in a number of domestic power facilities and was the principal equity investment through which we conducted our domestic power activities. We consolidated Chaparral and its related power plants in early 2003. In 2003 and 2004, among other impairments noted in the table above, we recorded substantial impairments, net of gains and losses based on the anticipated sale of our merchant and contracted plants, as well as operational and contractual issues at several of these facilities. Included in these amounts was a $25 million loss in 2004 on the termination of a power contract with our Marketing and Trading segment related to one of the assets sold, which was eliminated in consolidation. As these facilities were sold through 2004, we experienced lower EBIT in each year from the operation of these facilities. See Financial Statements and Supplementary Data, Notes 2, 3, and 21 for a further discussion of these matters.

Field Services Segment

As of December 31, 2005, the remaining assets in our Field Services segment are our Bluebell and Altamont facilities located in the Rocky Mountain area. Effective January 1, 2006, these assets have been transferred to our Exploration and Production segment, as they primarily support our producing activities in that segment.

Prior to their sales from 2003 through the third quarter of 2005, our general and limited partner interests in GulfTerra and Enterprise and gathering and processing assets in south Texas and south Louisiana were the primary sources of earnings in our Field Services segment. The sales of these assets are further described in Financial Statements and Supplementary Data, Note 21. Our south Louisiana operations are reported as discontinued operations for the three years ended December 31, 2005. The tables below and discussion that follows provide the operating results and additional analysis of significant factors affecting EBIT for our Field Services segment for each of the three years ended December 31:


			2005			2004			2003

			(In millions)
Gathering and processing gross margins⁽¹⁾			$	25		$	93		$	96
Operating expenses
	Loss on long-lived assets			(10	)		(507	)		(173	)
	Other operating expenses			(31	)		(87	)		(120	)

		Operating loss		(16	)		(501	)		(197	)
Earnings from unconsolidated affiliates				301			618			329
Other expense				—			(33	)		(3	)

		EBIT	$	285		$	84		$	129


⁽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 historically were a significant factor in the determination of profit from our midstream activities.


			2005			2004			2003

			(In millions)
Gathering and Processing Activities
	Gathering and processing margins		$	25		$	93		$	96
	Operating expenses			(8	)		(87	)		(120	)
	Other income (expense)			7			11			(7	)

		EBIT		24			17			(31	)

GulfTerra/Enterprise-related Items
	Assets sold to GulfTerra			5			9			(7	)
	Assets/interests sold to Enterprise
		Sale of GP/LP interests		183			507			266
		Sale of south Texas		—			(11	)		(167	)
		Goodwill impairment		—			(480	)		—
		Other		(1	)		(45	)		—
	Equity earnings			—			100			153

		EBIT		187			80			245

Other Asset Sales
	Sale of Javelina investment			111			—			—
	Dauphin Island/ Mobile Bay			—			—			(86	)
	Termination of Needle Mountain gas supply contract			(28	)		—			—
	Other			(9	)		(13	)		1

				74			(13	)		(85	)

		EBIT	$	285		$	84		$	129

Gathering and Processing Activities. During the three years ended December 31, 2005, the decreases in our gross margins and in operation and maintenance expenses were primarily a result of asset sales, including the sales of our south Texas, north and south Louisiana, mid-continent and Indian Springs gathering and processing plants.

GulfTerra/Enterprise Related Items. During 2002 and 2003, we sold a number of assets to GulfTerra. While these sales decreased our gross margin and operating expenses, they increased the equity earnings from our general and limited partner interests in GulfTerra. However, over time, our equity earnings in GulfTerra declined as we sold our interests in that investment. The effect of significant transactions related to GulfTerra during 2005, 2004 and 2003 were as follows:


	•	Gain of $266 million on the sale of 50 percent of our interest in GulfTerra to Enterprise in 2003. At the same time, we recorded an impairment of our south Texas assets of $167 million based on the planned sale of these assets to Enterprise;

	•	Gain of $507 million upon the sale of our remaining 50 percent interest in the general partner of GulfTerra to Enterprise in 2004. As a result of this sale, we also impaired goodwill recorded on the segment; and

	•	Gain of $183 million on the sale of our remaining general partner and limited partner interests in Enterprise in 2005.

Corporate and Other Expenses, Net

Our corporate activities include our general and administrative functions as well as a number of miscellaneous businesses, which do not qualify as operating segments and are not material to our current year

results. The following is a summary of significant items impacting the EBIT in our corporate operations for each of the three years ended December 31:


		2005			2004			2003

		(In millions)
Change in litigation, insurance and other reserves		$	(418	)	$	(81	)	$	(10	)
Western Energy Settlement			(72	)		(38	)		(2	)
Impairments, contract terminations and gains (losses) on asset sales:
	Telecommunications business		5			—			(396	)
	LNG business		—			—			(108	)
	Aircraft		—			8			(8	)
Other operating earnings (losses) from other businesses			21			32			(22	)
Restructuring charges			(27	)		(91	)		(91	)
Debt gains (losses):
	Foreign currency fluctuations on Euro-denominated debt		36			(26	)		(112	)
	Early extinguishment/exchange of debt		(29	)		(18	)		(49	)
Other			(37	)		(3	)		(54	)

Total EBIT		$	(521	)	$	(217	)	$	(852	)

We have a number of pending litigation matters, including shareholder and other lawsuits filed against us. In all of our legal and insurance matters, we evaluate each lawsuit and claim as to its merits and our defenses. Adverse rulings or unfavorable settlements against us related to these matters have impacted and may further impact our future results. In 2005 and 2004, we recorded significant charges in operation and maintenance expense to increase our litigation, insurance and other reserves based on ongoing assessments, developments and evaluations of the possible outcomes of these matters. In 2005, the most significant item was a charge in connection with a ruling by an appellate court that we indemnify a former subsidiary for certain payments being made under a retiree benefit plan. Additionally, we incurred charges in 2005 with the final prepayment of the Western Energy Settlement and charges related to increased premiums from a mutual insurance company in which we participate, based primarily on the impact of several hurricanes in 2004 and 2005. In 2004, we also incurred charges associated with the Western Energy Settlement obligation and charges related to our decision to withdraw from another mutual insurance company in which we were a member.

As discussed in Financial Statements and Supplementary Data, Note 4, we accrued $80 million in 2004 related to the consolidation of our Houston-based operations. Our relocation costs were based on a discounted liability, which included estimates of future sublease rentals. During 2005, we recorded additional charges of $27 million related to vacating the remaining leased space and signing a termination agreement on the lease.

Interest and Debt Expense

The table below and discussion that follows provide an analysis of our interest and debt expense for each of the three years ended December 31:


		2005		2004		2003

		(In millions)
Long-term debt, including current maturities		$	1,321	$	1,494	$	1,674
Other interest			33		74		94

	Total interest and debt expense	$	1,354	$	1,568	$	1,768

Our total interest and debt expense decreased between 2003 and 2005 primarily due to the retirements of debt and other financing obligations, net of issuances. During 2005, our overall debt level declined by approximately $0.9 billion through a combination of repayments and asset sales, net of issuances. In 2004, our overall debt levels declined by $2.5 billion. See Financial Statements and Supplementary Data, Note 14, for a further discussion of our activities related to debt repayments and issuances.

Distributions on Preferred Interests of Consolidated Subsidiaries

Our distributions on preferred securities decreased significantly between 2003 and 2005 due to the redemption, or reclassification as debt, of substantially all of these securities during these periods. For a further discussion of our borrowings and other financing activities related to our consolidated subsidiaries, see Financial Statements and Supplementary Data, Notes 14 and 15.

Income Taxes

Income taxes for the years ended December 31, 2005, 2004 and 2003 were a benefit of $251 million, $43 million and $530 million, resulting in effective tax rates of 42 percent, 5 percent and 44 percent. Differences in our effective tax rates from the statutory tax rate of 35 percent were primarily a result of the following factors:


	•	earnings from unconsolidated affiliates where we anticipate receiving dividends;

	•	foreign income taxed at different rates;

	•	sales and write offs of foreign investments;

	•	valuation allowances;

	•	audit settlements;

	•	non-deductible goodwill impairments; and

	•	non-taxable medicare reimbursements.

In 2004, our overall effective tax rate on continuing operations was significantly different than the statutory rate due primarily to sales of our GulfTerra investment and impairments of certain of our foreign investments. The sale of GulfTerra resulted in a significant net taxable gain (compared to a lower book gain) and thus significant tax expense due to the non-deductibility of 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. Additionally, we received no U.S. federal income tax benefit on the impairment of certain of our foreign investments. The combination of these items resulted in an overall tax expense in a period for which there was a pre-tax loss. The effective tax rate for 2004 absent these items would have been 37 percent.

We have pending IRS and other taxing authority audits and income tax contingencies that are in various stages of completion. We have recorded a liability on these matters based on our best estimate of the ultimate outcome of each matter. As these audits are finalized and as these contingencies are resolved, we 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 future periods. We had several such adjustments in 2005 which impacted our effective tax rate.

For a reconciliation of the statutory rate to our effective tax rate, valuation allowances and additional discussion of other income tax matters affecting us, see Financial Statements and Supplementary Data, Note 7.

Discontinued Operations

We present our gathering and processing operations in south Louisiana, certain international power operations, petroleum markets operations and international natural gas and oil production operations outside of Brazil as discontinued operations in our financial statements. For the years ended December 31, 2005, 2004, and 2003, losses from our discontinued operations were $250 million, $43 million and $1.2 billion. Our 2005 loss was primarily a result of impairments of our discontinued international power operations partially offset by the sale of our south Louisiana operations in the fourth quarter of 2005. The impairments of our international power assets and the gain on the sale of south Louisiana are further discussed in Financial Statements and Supplementary Data, Note 3. Our 2004 losses related primarily to charges and losses on the sales of discontinued assets along with other operational and severance costs, partially offset by earnings from the Macae power plant in Brazil. The losses in 2003 related primarily to impairment charges on our discontinued

petroleum refineries and on chemical assets and ceiling test charges related to our discontinued Canadian production operations, partially offset by earnings from the Macae power plant in Brazil.

Commitments and Contingencies

For a discussion of our commitments and contingencies, see Financial Statements and Supplementary Data, Note 16.

Critical Accounting Policies

Our critical accounting policies are those 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.

Price Risk Management Activities. We record the derivative instruments used in our price risk management activities at their fair values on 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 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 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

	(In millions)
Derivatives designated as hedges	$	(653	)	$	(751	)	$	(98	)	$	(555	)	$	98
Other commodity-based derivatives		(763	)		(903	)		(140	)		(626	)		137

Total	$	(1,416	)	$	(1,654	)	$	(238	)	$	(1,181	)	$	235

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 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 positions.

Accounting for Natural Gas and Oil Producing Activities. Natural gas and oil reserves estimates underlie a number of the accounting estimates in our financial statements. 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, 2005, of our total proved reserves, 31 percent were undeveloped and 12 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, exploration and development 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 less than $1 million, $35 million and $76 million during 2005, 2004 and 2003.

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 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, 2005 would not have resulted in a ceiling test charge in 2005.

Asset and Investment Impairments. The accounting rules on asset and investment impairments 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. Actual results 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 $73 million, $1.1 billion and $791 million and impairments on our investments in unconsolidated affiliates of $347 million, $397 million, and $449 million during the years ended December 31, 2005, 2004 and 2003. We also recorded asset and investment impairments of our discontinued operations of $502 million, $40 million and $1.5 billion, net of minority interest during the years ended December 31, 2005, 2004 and 2003. Future changes in the economic and business environment can impact our assessments of potential impairments.

Accounting for Legal and Environmental Reserves. We accrue legal and 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 our evaluation of potential outcomes, currently available facts, and in the case of environmental reserves, existing technology and presently enacted laws and regulations taking into consideration the likely effects of societal and economic factors, 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 matter.

As of December 31, 2005, we had accrued approximately $574 million for legal matters and $379 million for environmental matters. Our environmental estimates range from approximately $379 million to approximately $546 million, and the amounts we have accrued represent a combination of two estimation methodologies. First, where the most likely outcome can be reasonably estimated, that cost has been accrued ($75 million). Second, where the most likely outcome cannot be estimated, a range of costs is established ($304 million to $471 million) and the lower end of the expected range has been accrued.

Accounting for Pension and Other Postretirement Benefits. As of December 31, 2005, we had a $918 million pension asset and a $250 million liability for other postretirement benefits reflected in other assets and liabilities on our balance sheet related to our pension and other postretirement benefit plans. These amounts are primarily based on actuarial calculations. We use various assumptions in performing these calculations, including those related to the return that we expect to earn on our plan assets, 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. A significant assumption we utilize is the discount rates used in calculating our benefit obligations. We select our discount rates by comparing the average expected timing of our pension and other postretirement obligations to the maturity profiles of the Moody’s Corporate Bond Indices and the Citigroup Pension Discount Curve. Based on these comparisons, we select discount rates that appropriately reflect the yields included in these market sources adjusted for the estimated timing of our obligations.

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 either the period of expected future service of active participants, or over the lives of the plan participants. The cumulative amount deferred as of December 31, 2005 is recorded as an $814 million increase in our pension asset and a $20 million reduction of our other postretirement liability. The following table shows the impact of a one percent change in the primary assumptions used in our actuarial calculations associated with our pension and other postretirement benefits for the year ended December 31, 2005 (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	$	(14	)	$	(205	)	$	—		$	(41	)
	Expected return on plan assets		(21	)		—			(2	)		—
	Rate of compensation increase		1			6			—			—
	Health care cost trends		—			—			1			20

One percent decrease in:
	Discount rates	$	15		$	245		$	—		$	44
	Expected return on plan assets ⁽¹⁾		21			—			2			—
	Rate of compensation increase		(1	)		(5	)		—			—
	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 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 $19 million lower for the year ended December 31, 2005.

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 $212 million and $226 million as of September 30, 2005 and December 31, 2005. If the accumulated benefit obligation exceeded plan assets under this primary pension plan as of September 30, 2005, we would have recorded a pre-tax additional pension liability of approximately $918 million, plus an amount equal to the excess of the accumulated benefit obligation over the assets of that plan. We would have also recorded an amount equal to this additional pension liability in accumulated other comprehensive loss, net of taxes, on our balance sheet.

As stated in Financial Statements and Supplementary Data, Note 16, we were ordered to indemnify a third party for certain benefit payments being made to a closed group of retirees pending the outcome of litigation related to these payments. We estimated the liability associated with this indemnification obligation using actuarial methods similar to those used in estimating our obligations on our other postretirement benefit plans, which involves using various assumptions, including those related to discount rates and health care trends. A one percent change in the discount rate assumption used in the calculation would have changed the liability (and the related expense) by approximately $45 million and a one percent change in the health care cost trend assumption would have changed the liability (and the related expense) by approximately $50 million as of and for the year ended December 31, 2005.

New Accounting Pronouncements Issued But Not Yet Adopted

See Financial Statements and Supplementary Data, Note 1 under New Accounting Pronouncements Issued But Not Yet Adopted.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to 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 and oil price changes, impacting the forecasted sale of natural gas and oil in our Exploration and Production segment;

	–	Locational price differences in natural gas changes, affecting our ability to optimize pipeline transportation capacity contracts held in our Marketing and Trading segment; and

	–	Electricity and natural gas price changes and locational pricing changes, affecting the value of our natural gas contracts and remaining power contracts held in our Marketing and Trading and Power segments. During 2005, we assigned or entered into agreements to assign to third parties the majority of our power contract portfolio, including our Cordova tolling agreement. As a result, our sensitivity to change in power prices will be significantly reduced in future periods.


	•	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;

	–	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; and

	–	Changes in interest rates used to discount liabilities which can result in higher or lower accretion expense over time.


	•	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 entering into contractual commitments involving physical or financial settlement that attempt to limit exposure 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;

	•	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 use in our risk management activities are derivative financial instruments. A discussion of our accounting policies for derivative instruments are included in Financial Statements and Supplementary Data, Notes 1 and 10.

Commodity Price Risk

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 allows us to monitor our risk in comparison to established thresholds. We use what is known as the historical simulation technique for measuring Value-at-Risk. This technique simulates potential outcomes in the value of our portfolio based on market-based price changes. Our exposure to changes in fundamental prices over the long-term can vary from the exposure using the one-day assumption in our Value-at-Risk simulations. We supplement our Value-at-Risk simulations with additional fundamental and market-based price analyses, including scenario analysis and stress testing to determine our portfolio’s sensitivity to its underlying risks. These analyses and our Value-at-Risk simulations do not include the commodity exposures of our Exploration and Production segment’s sales of natural gas and oil production.

Our maximum expected one-day unfavorable impact on the fair values of our 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 $60 million and $16 million as of December 31, 2005 and 2004. Our highest, lowest and average of the month-end values for Value-at-Risk during 2005 was $60 million, $12 million and $36 million. Our Value-at-Risk increased significantly during 2005 due to several financial swaps and option contracts that we entered into during 2004 and 2005 to provide price protection on a portion of the Company’s anticipated natural gas and oil production. These contracts increased our exposure to market changes in natural gas and oil prices, which were volatile during 2005. This volatility may continue into the future and actual losses in fair value may exceed those measured by Value-at-Risk.

Exploration and Production

Our Exploration and Production segment attempts to mitigate commodity price risk and to stabilize cash flows associated with its forecasted sales of 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 used to mitigate these market risks. 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			(Decrease)			Fair Value			Increase

		(In millions)
Impact of changes in commodity prices on derivative commodity instruments
	December 31, 2005	$	(684	)	$	(786	)	$	(102	)	$	(582	)	$	102
	December 31, 2004	$	(557	)	$	(697	)	$	(140	)	$	(417	)	$	140

Interest Rate Risk

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 long-term interest-bearing securities by expected maturity dates as well as the total fair value of those securities. The fair value of the securities has been estimated based on quoted market prices for the same or similar issues.


		December 31, 2005																						December 31, 2004

		Expected Fiscal Year of Maturity of Carrying Amounts
																						Fair		Carrying		Fair
		2006⁽¹⁾			2007			2008			2009			2010			Thereafter			Total		Value		Amounts		Value

		(In millions)
Long-term debt and other obligations, including current portion — fixed rate		$	952		$	747		$	643		$	1,300		$	1,536		$	10,841		$	16,019	$	16,463	$	17,587	$	18,227
	Average interest rate		4.6	%		6.7	%		6.9	%		6.5	%		8.5	%		7.6	%
Long-term debt and other obligations, including current portion — variable rate		$	34		$	33		$	33		$	1,179		$	515		$	196		$	1,990	$	1,990	$	1,282	$	1,282
	Average interest rate		6.2	%		6.1	%		6.1	%		6.2	%		6.1	%		5.9	%


⁽¹⁾	Excludes amounts related to Macae, which are included in liabilities related to discontinued operations. Macae has fixed rate debt of $110 million at an average interest rate of 7.0% and variable rate debt of $115 million at an average interest rate of 10.4%.

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, 2005, we have Euro-denominated debt with a principal amount of €522 million of which €22 million matures in 2006 and €500 million matures in 2009. As of December 31, 2005 and 2004, we had swaps that effectively converted €367 million and €725 million of debt into $418 million and $766 million. The remaining principal at December 31, 2005 and 2004 of €155 million and € 325 million was subject to foreign currency exchange risk.

Power Contracts

Several of our international power plants in Asia, Central America and South America have long-term power sales contracts that are denominated in the local country’s currencies. Because we expect to sell substantially all of our Asian and Central American power plants during the first half of 2006, our exposure to foreign currency exchange risk related to these power sales contracts will end when the related power plants are sold. We do not believe that the remaining exposure is material to our operations and have not chosen to mitigate this exposure.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index

Below is an index to the items contained in Financial Statements and Supplementary Data.


		Page

Management’s Annual Report on Internal Control over Financial Reporting			71
Report of Independent Registered Public Accounting Firm			72
Consolidated Statements of Income			74
Consolidated Balance Sheets			75
Consolidated Statements of Cash Flows			77
Consolidated Statements of Stockholders’ Equity			79
Consolidated Statements of Comprehensive Income			80
Notes to Consolidated Financial Statements			81
	1. Basis of Presentation and Significant Accounting Policies		81
	2. Acquisitions		89
	3. Divestitures		90
	4. Restructuring and Other Charges		92
	5. (Gain) Loss on Long-Lived Assets		93
	6. Other Income and Other Expenses		94
	7. Income Taxes		95
	8. Earnings Per Share		98
	9. Fair Value of Financial Instruments		98
	10. Price Risk Management Activities		98
	11. Regulatory Assets and Liabilities		103
	12. Other Assets and Liabilities		103
	13. Property, Plant and Equipment		104
	14. Debt, Other Financing Obligations and Other Credit Facilities		105
	15. Preferred Interests of Consolidated Subsidiaries		110
	16. Commitments and Contingencies		110
	17. Retirement Benefits		120
	18. Capital Stock		124
	19. Stock-Based Compensation		125
	20. Business Segment Information		127
	21. Investments in, Earnings from and Transactions with Unconsolidated Affiliates		130
Supplemental Financial Information
	Supplemental Selected Quarterly Financial Information (Unaudited)		135
	Supplemental Natural Gas and Oil Operations (Unaudited)		136
Financial Statement Schedule
	Schedule II — Valuation and Qualifying Accounts		142

MANAGEMENT’S ANNUAL REPORT ON

INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined by the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is 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. It consists of policies and procedures that:


	•	Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

	•	Provide reasonable assurance that transactions are recorded as necessary to permit preparation of the financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and

	•	Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

Under the supervision and with the participation of management, including the Chief Executive Officer(CEO) and Chief Financial Officer(CFO), we made an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005. 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). Based on our evaluation, we concluded that our internal control over financial reporting was effective as of December 31, 2005. Our assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report included herein.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

El Paso Corporation:

We have completed integrated audits of El Paso Corporation’s 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005, and an audit of its 2003 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 (the “Company”) at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 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 the financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and the 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 the notes to the consolidated financial statements, the Company adopted FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, on December 31, 2005, 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, FASB Interpretation No. 46, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51, on January 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 and SFAS No. 143, Accounting for Asset Retirement Obligations.

Internal Control Over Financial Reporting

Also, in our opinion, management’s assessment, included in Management’s Annual Report on Internal Control Over Financial Reporting appearing under Item 8, that the Company maintained effective internal control over financial reporting as of December 31, 2005 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 Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control — Integrated Framework issued by the 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 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.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 2, 2006, except for the sixth paragraph

of Note 3, as to which the date is May 10, 2006

EL PASO CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(In millions, except per common share amounts)


		Year Ended December 31,

		2005			2004			2003

Operating revenues
	Pipelines	$	2,783		$	2,651		$	2,647
	Exploration and Production		1,787			1,735			2,141
	Marketing and Trading		(796	)		(508	)		(635	)
	Power		82			402			873
	Field Services		123			1,097			1,283
	Corporate and eliminations		(9	)		(89	)		(151	)

			3,970			5,288			6,158

Operating expenses
	Cost of products and services		323			1,218			1,637
	Operation and maintenance		2,032			1,710			1,972
	Depreciation, depletion and amortization		1,100			1,043			1,137
	Loss on long-lived assets		74			1,077			860
	Taxes, other than income taxes		262			224			276

			3,791			5,272			5,882

Operating income (loss)			179			16			276
Earnings from unconsolidated affiliates			342			546			363
Other income			289			182			191
Other expenses			(50	)		(98	)		(202	)
Interest and debt expense			(1,354	)		(1,568	)		(1,768	)
Distributions on preferred interests of consolidated subsidiaries			(9	)		(25	)		(52	)

Loss before income taxes			(603	)		(947	)		(1,192	)
Income taxes			(251	)		(43	)		(530	)

Loss from continuing operations			(352	)		(904	)		(662	)
Discontinued operations, net of income taxes			(250	)		(43	)		(1,212	)
Cumulative effect of accounting changes, net of income taxes			(4	)		—			(9	)

Net loss			(606	)		(947	)		(1,883	)
Preferred stock dividends			27			—			—

Net loss available to common stockholders		$	(633	)	$	(947	)	$	(1,883	)

Basic and diluted loss per common share
	Loss from continuing operations	$	(0.59	)	$	(1.41	)	$	(1.11	)
	Discontinued operations, net of income taxes		(0.38	)		(0.07	)		(2.02	)
	Cumulative effect of accounting changes, net of income taxes		(0.01	)		—			(0.02	)

	Net loss per common share	$	(0.98	)	$	(1.48	)	$	(3.15	)

Basic and diluted average common shares outstanding			646			639			597

See accompanying notes.

EL PASO CORPORATION

CONSOLIDATED BALANCE SHEETS

(In millions, except share amounts)


				December 31,

				2005		2004

ASSETS
Current assets
	Cash and cash equivalents			$	2,132	$	2,117
	Accounts and notes receivable
		Customer, net of allowance of $67 in 2005 and $198 in 2004			1,115		1,287
		Affiliates			58		133
		Other			141		187
	Assets from price risk management activities				641		601
	Margin and other deposits held by others				1,124		79
	Assets held for sale and from discontinued operations				230		388
	Deferred income taxes				396		418
	Other				348		422

			Total current assets		6,185		5,632

Property, plant and equipment, at cost
	Pipelines				19,965		19,418
	Natural gas and oil properties, at full cost				15,738		14,968
	Other				651		1,493

					36,354		35,879
	Less accumulated depreciation, depletion and amortization				17,567		18,030

			Total property, plant and equipment, net		18,787		17,849

Other assets
	Investments in unconsolidated affiliates				2,473		2,574
	Assets from price risk management activities				1,368		1,584
	Goodwill and other intangible assets, net				413		421
	Other				2,612		3,323

					6,866		7,902

			Total assets	$	31,838	$	31,383

See accompanying notes.

EL PASO CORPORATION

CONSOLIDATED BALANCE SHEETS

(In millions, except share amounts)


				December 31,

				2005			2004

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
	Accounts payable
		Trade		$	864		$	965
		Affiliates			10			21
		Other			540			469
	Short-term financing obligations, including current maturities				986			635
	Liabilities from price risk management activities				1,418			852
	Liabilities related to discontinued operations				420			450
	Margin deposits held by us				497			131
	Accrued interest				290			327
	Other				687			722

			Total current liabilities		5,712			4,572

Long-term financing obligations, less current maturities					17,023			18,241

Other
	Liabilities from price risk management activities				2,005			1,026
	Deferred income taxes				1,405			1,245
	Other				2,273			2,494

					5,683			4,765

Commitments and contingencies
Securities of subsidiaries
	Securities of consolidated subsidiaries				31			367
Stockholders’ equity
	Preferred stock, par value $0.01 per share; authorized 50,000,000 shares; issued 750,000, 4.99% convertible perpetual shares in 2005; stated at liquidation value				750			—
	Common stock, par value $3 per share; authorized 1,500,000,000 shares; issued 667,082,043 shares in 2005 and 651,064,508 shares in 2004				2,001			1,953
	Additional paid-in capital				4,592			4,538
	Accumulated deficit				(3,415	)		(2,809	)
	Accumulated other comprehensive income (loss)				(332	)		1
	Treasury stock (at cost); 7,620,272 shares in 2005 and 7,767,088 shares in 2004				(190	)		(225	)
	Unamortized compensation				(17	)		(20	)

			Total stockholders’ equity		3,389			3,438

			Total liabilities and stockholders’ equity	$	31,838		$	31,383

See accompanying notes.

EL PASO CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)


					Year Ended December 31,

					2005			2004			2003

Cash flows from operating activities
	Net loss				$	(606	)	$	(947	)	$	(1,883	)
	Less loss from discontinued operations, net of income taxes					(250	)		(43	)		(1,212	)

	Net loss before discontinued operations					(356	)		(904	)		(671	)
	Adjustments to reconcile net loss to net cash from operating activities
		Depreciation, depletion and amortization				1,100			1,043			1,137
		Deferred income tax benefit				(228	)		(72	)		(620	)
		Loss on long-lived assets				74			1,077			785
		Earnings from unconsolidated affiliates, adjusted for cash distributions				(63	)		(211	)		(17	)
		Other non-cash income items				361			437			495
		Asset and liability changes
			Accounts and notes receivable			96			492			2,550
			Change in price risk management activities, net			325			191			85
			Accounts payable			(102	)		(321	)		(2,066	)
			Broker and other margins on deposit with others			(1,045	)		121			623
			Broker and other margins on deposit with us			366			(24	)		32
			Western Energy Settlement liability			(395	)		(626	)		—
			Other asset changes			232			14			(188	)
			Other liability changes			(90	)		(309	)		90

			Cash provided by continuing activities			275			908			2,235
			Cash provided by discontinued activities			(7	)		408			94

				Net cash provided by operating activities		268			1,316			2,329

Cash flows from investing activities
	Capital expenditures					(1,717	)		(1,803	)		(2,351	)
	Cash paid for acquisitions, net of cash acquired					(1,025	)		(47	)		(333	)
	Net proceeds from the sale of assets and investments					1,424			1,927			2,458
	Net change in restricted cash					(48	)		551			(468	)
	Net change in notes receivable from affiliates					11			120			(43	)
	Other					192			(1	)		—

			Cash provided by (used in) continuing activities			(1,163	)		747			(737	)
			Cash provided by (used in) discontinued activities			662			1,156			(452	)

				Net cash provided by (used in) investing activities		(501	)		1,903			(1,189	)

See accompanying notes.

EL PASO CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)


				Year Ended December 31,

				2005			2004			2003

Cash flows from financing activities
	Net proceeds from issuance of long-term debt				1,620			1,254			3,264
	Payments to retire long-term debt and other financing obligations				(1,565	)		(2,208	)		(2,814	)
	Net repayments under revolving and other short-term credit facilities				—			(850	)		(650	)
	Net proceeds from issuance of notes payable				—			—			84
	Repayment of notes payable				—			(214	)		(8	)
	Net proceeds from issuance of preferred stock				723			—			—
	Payments to minority interest and preferred interest holders				(306	)		(35	)		(1,277	)
	Issuances of common stock				—			73			120
	Dividends paid				(121	)		(101	)		(203	)
	Contributions from discontinued operations				552			1,147			1
	Other				—			(33	)		(177	)

		Cash provided by (used in) continuing activities			903			(967	)		(1,660	)
		Cash provided by (used in) discontinued activities			(655	)		(1,564	)		358

			Net cash provided by (used in) financing activities		248			(2,531	)		(1,302	)

Change in cash and cash equivalents					15			688			(162	)
Cash and cash equivalents
	Beginning of period				2,117			1,429			1,591

	End of period			$	2,132		$	2,117		$	1,429

Supplemental Cash Flow Information Related to Continuing Operations
	Interest paid, net of amounts capitalized			$	1,308		$	1,499		$	1,639
	Income tax payments (refunds)				11			37			(19	)

See accompanying notes.

EL PASO CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In millions, except per share amounts)


			For the Years Ended December 31,

			2005						2004						2003

			Shares			Amount			Shares			Amount			Shares			Amount

Preferred stock, $0.01 par value
	Balance at beginning of year			—		$	—			—		$	—			—		$	—
	Equity offering			1			750			—			—			—			—

	Balance at end of year			1			750			—			—			—			—

Common stock, $3.00 par value
	Balance at beginning of year			651			1,953			639			1,917			605			1,816
	Exchange of equity security units			14			41			—			—			15			45
	Western Energy Settlement equity offerings			—			—			9			26			18			53
	Other, net			2			7			3			10			1			3

		Balance at end of year		667			2,001			651			1,953			639			1,917

Additional paid-in capital:
	Balance at beginning of year						4,538						4,576						4,444
	Compensation related issuances						(18	)					15						8
	Tax effects of equity plans						2						5						(26	)
	Exchange of equity security units						230						—						189
	Western Energy Settlement equity offerings						—						46						67
	Dividends						(131	)					(104	)					(96	)
	Other						(29	)					—						(10	)

		Balance at end of year					4,592						4,538						4,576

Accumulated deficit:
	Balance at beginning of year						(2,809	)					(1,862	)					21
	Net loss						(606	)					(947	)					(1,883	)

		Balance at end of year					(3,415	)					(2,809	)					(1,862	)

Accumulated other comprehensive income (loss):
	Balance at beginning of year						1						(40	)					(235	)
	Other comprehensive income (loss)						(333	)					41						195

		Balance at end of year					(332	)					1						(40	)

Treasury stock, at cost:
	Balance at beginning of year			(8	)		(225	)		(7	)		(222	)		(6	)		(201	)
	Compensation related issuances			1			47			—			9			—			—
	Other			(1	)		(12	)		(1	)		(12	)		(1	)		(21	)

		Balance at end of year		(8	)		(190	)		(8	)		(225	)		(7	)		(222	)

Unamortized compensation:
	Balance at beginning of year						(20	)					(23	)					(95	)
	Issuance of restricted stock						(22	)					(28	)					(1	)
	Amortization of restricted stock						18						23						60
	Forfeitures of restricted stock						7						9						15
	Other						—						(1	)					(2	)

		Balance at end of year					(17	)					(20	)					(23	)

Total stockholders’ equity				659		$	3,389			643		$	3,438			632		$	4,346

See accompanying notes.

EL PASO CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In millions)


				Year Ended December 31,

				2005			2004			2003

Net loss				$	(606	)	$	(947	)	$	(1,883	)

	Foreign currency translation adjustments (net of income tax of $4 in 2005, $(38) in 2004 and $51 in 2003)				(9	)		11			108
	Minimum pension liability accrual (net of income tax of $2 in 2005, $11 in 2004 and $7 in 2003)				(3	)		(22	)		11
	Net gains (losses) from cash flow hedging activities:
		Unrealized mark-to-market gains (losses) arising during period (net of income tax of $229 in 2005, $8 in 2004 and $50 in 2003)			(415	)		22			101
		Reclassification adjustments for changes in initial value to settlement date (net of income tax of $46 in 2005, $8 in 2004 and $11 in 2003)			79			30			(25	)
	Change in unrealized gains on available for sale securities (net of income tax of $9 in 2005)				15			—			—

			Other comprehensive income (loss)		(333	)		41			195

Comprehensive loss				$	(939	)	$	(906	)	$	(1,688	)

See accompanying notes.

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 south Louisiana gathering and processing assets, which were part of our Field Services segment, certain of our international power operations our Canadian and certain other international natural gas and oil production operations, our petroleum markets operations and our coal mining operations 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.

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. On January 1, 2004, we adopted the provisions of FASB Financial Interpretation (FIN) No. 46, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51. The adoption of this standard did not have a material impact to our financial statements. For a further discussion of our variable interests, see Note 21.

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.

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, the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005. Of our regulated pipelines, all but ANR follow the regulatory accounting principles prescribed under Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation. ANR discontinued the application of SFAS No. 71 in 1996, primarily due to the level of competition and discounting in ANR’s market areas, uncertainties related to expired contracts and the construction of competing facilities. The accounting required by SFAS No. 71 differs from the accounting required for businesses that do not apply its provisions. Items that are generally recorded differently as a result of applying regulatory accounting requirements include postretirement employee benefit plan costs, an equity return component on regulated capital projects and certain costs included in, or expected to be included in, future rates.

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 on our balance sheet based on when we expect this cash to be used. As of December 31, 2005, we had $94 million of restricted cash in current assets and $168 million in other non-current assets. As of December 31, 2004, we had $103 million of restricted cash in current assets and $180 million in other non-current assets.

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.

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’ property, plant and equipment. 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⁾		1-66
Non-regulated systems
	Transmission and storage facilities	Straight-line		5-34
	Gathering and processing systems	Straight-line		3-35
	Buildings and improvements	Straight-line		9-25
	Office and miscellaneous equipment	Straight-line		1-15

⁽¹⁾

Under the composite (group) 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 operating 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 unevaluated costs related to our natural gas and oil properties, 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, 2005, 2004 and 2003, were $45 million,

$39 million and $31 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, 2005, 2004 and 2003 were $31 million, $22 million and $19 million. These amounts are included 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 evaluate our assets and investments for impairment when events or circumstances indicate that their carrying values 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) our long-lived assets’ ability to generate future cash flows on an undiscounted basis or (ii) the fair value of our investments in unconsolidated affiliates. If an impairment is indicated or if we decide to sell a long-lived asset or group of assets, we adjust the carrying values 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 being 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 significant 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. Under the full cost method, both dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and periodically assessed in our ceiling test calculations as discussed below.

Capitalized costs associated with proved reserves are amortized over the life of the reserves using the unit of production method. Conversely, capitalized costs associated with unproved properties are excluded from the amortizable base until these properties are evaluated, which occurs on a quarterly basis. Specifically, we transfer costs to the amortizable base when properties are determined to have proved reserves. In addition, we transfer unproved property costs to the amortizable base when unproved properties are evaluated as being impaired and as exploratory dry holes are determined to be unsuccessful. Additionally, the amortizable base includes future development costs and dismantlement, restoration and abandonment costs, net of estimated salvage values; and geological and geophysical costs incurred that cannot be associated with specific unevaluated properties or prospects in which we own a direct interest.

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 the ceiling is not greater than or equal to the total capitalized costs, we are required to write-down our capitalized costs to the ceiling. 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. Our ceiling test calculations exclude the estimated future cash outflows associated with asset retirement liabilities related to proved developed reserves.

When we sell or convey interests in our natural gas and oil properties, we reduce our natural gas and oil 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 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. Goodwill is not amortized, but instead is 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, 2005 and 2004 and the changes in the net carrying amounts of goodwill for the years ended December 31, 2005 and 2004 by segment are as follows:


				Field
		Pipelines		Services			Power			Total

		(In millions)
Goodwill as of January 1, 2004		$	413	$	480		$	3		$	896
Impairments of goodwill in 2004			—		(480	)		—			(480	)
Other changes in 2004			—		—			(3	)		(3	)

	Goodwill as of December 31, 2004 and 2005	$	413	$	—		$	—		$	413

The goodwill impairment in our Field Services segment resulted from the sales of our GulfTerra investment and certain segment assets. As a result of these sales, we determined that the remaining segment assets could not support the segment’s goodwill.

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, actuarial assumptions, and the passage of time), expected returns on plan assets and amortization of certain deferred gains and losses. For a further discussion of our policies with respect to our pension and postretirement plans, See Note 17.

In our balance sheet, changes in the recorded assets and liabilities associated with our primary pension plan and other postretirement benefit plans are based on the amounts of our contributions, benefit expense and changes in deferred gains and losses during a given period. Changes in the liabilities on our other pension plans are reported as changes in other comprehensive income, net of income taxes, on our financial statements. For a further discussion of the contributions, benefits and deferred gains and losses related to our pension and other postretirement obligations see Note 17.

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 accounted for as an actuarial gain in our postretirement benefit liabilities as of December 31, 2005 and 2004. The adoption of this guidance reduced 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. The revenue recognition policies of our most significant operating segments are as follows:

Pipelines revenues. Our Pipelines segment derives revenues primarily from transportation and storage services. For our transportation and storage services, we recognize reservation revenues on firm contracted capacity ratably over the contract period regardless of the amount of natural gas that is transported or stored. For interruptible or volumetric based services, we record revenues when physical deliveries of natural gas are made at the agreed upon delivery point or when gas is injected or withdrawn from the storage facility. Gas not needed for operations is based on the volumes we are allowed to retain relative to the amounts of gas we use for operating purposes. We recognize revenue from gas not used in operations when we retain the volumes under our tariffs. Revenues for all services are generally based on the thermal quantity of gas delivered or subscribed at a price specified in the contract. We are subject to FERC regulations and, as a result, revenues we collect in rate proceedings may be subject to refund. We establish reserves for these potential refunds.

Exploration and Production revenues. Our Exploration and Production segment derives revenues primarily through the physical sale of natural gas, oil, condensate and NGL. 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.

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 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.


	Environmental Costs and Other Contingencies

Environmental Costs. We record liabilities at their undiscounted amounts on our balance sheet in other current and long-term liabilities when our environmental assessments indicate that remediation efforts are probable and the costs 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 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. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and we recognize a current period charge in operation and maintenance expense when clean-up efforts do not benefit future periods.

We evaluate separately from our liability any amounts paid directly or reimbursed by government sponsored programs and potential recoveries or reimbursements of remediation costs from third parties including insurance coverage. When recovery is assured after an evaluation of their creditworthiness or solvency, we record and report an asset separately from the associated liability on our balance sheet.

Other Contingencies. 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 the associated 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 or otherwise reduce the commodity, interest rate and foreign currency exposure on our natural gas and oil production and our long-term debt;

	•	derivatives related to our historical power contract restructuring business; and

	•	derivatives related to trading activities that we historically entered into with the objective of generating profits from exposure to shifts or changes in market prices.

Our derivatives are reflected on 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.

Derivatives that we have designated as accounting hedges impact our revenues or expenses based on the nature and timing of the transactions that they hedge. Derivatives related to our power contract restructuring activities are marked-to-market and reflected as either revenues (for changes in the fair values of the power sales contracts) or expenses (for changes in the fair values of the power supply agreements). We report the changes in the fair value of our other derivative contracts in revenue.

In our cash flow statement, cash inflows and outflows associated with the settlement of our derivative instruments are recognized in operating cash flows (other than those derivatives intended to hedge the principal amounts of our foreign currency denominated debt). In our balance sheet, receivables and payables resulting from the settlement of our derivative instruments are reported as trade receivables and payables.


	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.


	Foreign Currency Translation

For foreign operations whose functional currency is the local currency, assets and liabilities are translated at year-end exchange rates and revenues and expenses are translated at average exchange rates prevailing during the year. The cumulative translation effects are included as a separate component of accumulated other comprehensive income (loss) in stockholders’ equity.


	Accounting for Asset Retirement Obligations

On January 1, 2003, we adopted SFAS No. 143, Accounting for Asset Retirement Obligations, which requires that we record a liability for retirement and removal costs of long-lived assets used in our business when the timing and/or amount of the settlement of those costs are relatively certain. On December 31, 2005, we adopted the provisions of FIN No. 47, Accounting for Conditional Asset Retirement Obligations, which requires that we record a liability for those retirement and removal costs in which the timing and/or amount of the settlement of the costs are uncertain.

We have legal obligations associated with our natural gas and oil wells and related infrastructure, our natural gas pipelines and related transmission facilities and storage wells, as well as in our corporate headquarters building. We have obligations to plug wells when production on those wells is exhausted or we no

longer plan to use them, and when we abandon them. Our legal obligations associated with our natural gas transmission facilities relate primarily to purging and sealing the pipelines if they are abandoned. We also have obligations to remove hazardous materials associated with our natural gas transmission facilities and in our corporate headquarters if these facilities are replaced or renovated. We accrue a liability on those legal obligations when we can estimate the timing and amount of their settlement. These obligations include those where we have plans to or otherwise will be legally required to replace, remove or retire the associated assets. Substantially all of our natural gas pipelines can be maintained indefinitely and, as a result, we have not accrued a liability associated with purging and sealing them.

Our asset retirement liabilities are recorded at their estimated fair value 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. Many of our regulated pipelines have the ability to file for recovery of certain of these costs from their customers and have recorded an asset (rather than expense) associated with the depreciation of the property, plant and equipment and accretion of the liabilities described above. We recorded a charge as a cumulative effect of accounting change, net of income taxes of $4 million in 2003 and $2 million in 2005, of approximately $9 million in the first quarter of 2003 and $4 million in the fourth quarter of 2005 related to our adoption of SFAS No. 143 (primarily related to our Exploration and Production segment), and FIN No. 47 (primarily related to our Pipelines segment and our corporate activities), respectively.

In estimating the liability associated with our asset retirement obligations, we utilize several assumptions, including credit-adjusted discount rates ranging from six to eight percent, a projected inflation rate of 2.5 percent and the estimated timing and amount of settling our obligations, which are based on internal models and external quotes. The net asset retirement liability as of December 31 reported on our balance sheet in other current and non-current liabilities, and the changes in the net liability for the years ended December 31, were as follows:


		2005			2004

		(In millions)
Net asset retirement liability at January 1		$	322		$	269
Liabilities settled⁽¹⁾			(93	)		(38	)
Accretion expense			28			25
Liabilities incurred			19			36
Changes in estimate			(16	)		30
Adoption of FIN No. 47			15			—

	Net asset retirement liability at December 31	$	275		$	322


⁽¹⁾	Increase is due primarily to the sale of certain domestic natural gas and oil properties in our Exploration and Production segment. For a further discussion of these divestitures see Note 3.

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. If we had adopted the provisions of FIN No. 47 as of January 1, 2004, our asset retirement liability would have been higher by approximately $13 million and $14 million as of January 1, 2004 and December 31, 2004, and our net income for the years ended December 31, 2004 and 2005 would not have been materially affected.


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

On July 1, 2003, we adopted the provisions of SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity 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 on our balance sheet as required by that standard. We also began classifying dividends accrued on these preferred interests as interest and debt expense in our income statement.


	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 grant stock awards under stock option plans, restricted stock plans, and employee stock purchase programs. 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 the fair value recognition provisions of SFAS No. 123, Accounting for Stock-Based Compensation, rather than APB No. 25, the net loss available to common stockholders and per share impacts on our financial statements would have been different. The following table shows the impact on net loss available to common stockholders and loss per share had we applied SFAS No. 123 (See Note 19 for the weighted average assumptions of our options granted in 2005, 2004 and 2003):


		Year Ended December 31,

		2005			2004			2003

		(In millions, except per common
		share amounts)
Net loss available to common stockholders, as reported		$	(633	)	$	(947	)	$	(1,883	)
Add: Stock-based employee compensation expense included in reported net loss, net of taxes			12			14			38
Deduct: Total stock-based compensation expense determined under fair-value based method for all awards, net of taxes⁽¹⁾			(19	)		(25	)		(38	)

Net loss available to common stockholders, pro forma		$	(640	)	$	(958	)	$	(1,883	)

Loss per share:
	Basic and diluted, as reported	$	(0.98	)	$	(1.48	)	$	(3.15	)

	Basic and diluted, pro forma	$	(0.99	)	$	(1.50	)	$	(3.15	)


⁽¹⁾	Amounts have been adjusted from those previously reported to reflect the impact of actual forfeitures of unvested stock option awards on proforma compensation expense.


	New Accounting Pronouncements Issued But Not Yet Adopted

As of December 31, 2005, 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. 123(R), Share-Based Payment. This standard and related interpretations amend previous stock-based compensation guidance and require companies to measure all employee stock-based compensation awards at fair value on the date they are granted to employees and recognize compensation cost in its financial statements over the requisite service period. The fair value of options is determined by a model (e.g. Black-Scholes or binomial) using a variety of assumptions, the most significant of which are expected price volatility and expected term of the option. We also make assumptions about expected forfeiture rates. Our assumptions for new awards upon adoption of this standard could differ from those we have historically utilized. We will adopt SFAS No. 123(R) and related interpretations on January 1, 2006 prospectively for awards of stock-based compensation granted after that date and for the unvested portion of outstanding awards at that date. Based on the stock-based compensation awards outstanding as of December 31, 2005 and our anticipated level of stock-based compensation awards in 2006, we expect to record incremental compensation expense of approximately $15 million to $20 million as a result of adopting this standard.

Accounting for Pipeline Integrity Costs. In June 2005, the FERC issued an accounting release that will impact certain costs our interstate pipelines incur related to their pipeline integrity programs requiring us to

prospectively expense certain costs incurred after January 1, 2006, instead of our current practice of capitalizing them as part of our property, plant and equipment. In December 2005, FERC approved a request to allow one of our regulated pipeline subsidiaries, EPNG, to adopt the provisions of this release in December 2005, which did not have a material impact on our financial statements for the year ended December 31, 2005. We currently estimate that we will be required to expense an additional amount of pipeline integrity costs under this accounting release in the range of approximately $26 million to $41 million annually.

2. Acquisitions

Medicine Bow. In August 2005, we acquired Medicine Bow, a privately held energy company for total cash consideration of $853 million. Medicine Bow owns a 43.1 percent interest in Four Star, an unconsolidated affiliate. Our proportionate share of the future operating results associated with Four Star will be reflected as earnings from unconsolidated affiliates in our financial statements.

The Medicine Bow acquisition was accounted for using the purchase method of accounting. No goodwill was recorded associated with the acquisition. As part of our purchase price allocation, we allocated approximately $0.4 billion to property, plant, and equipment (of which $0.3 billion related to properties in our natural gas and oil full cost pool), $0.8 billion to our unconsolidated investment in Four Star, and $0.4 billion related to deferred tax liabilities. We reflected Medicine Bow’s results of operations in our income statement beginning September 1, 2005. The following summary unaudited pro forma consolidated results of operations for the years ended December 31, 2005 and 2004 reflect the combination of our historical income statements with Medicine Bow, adjusted for certain effects of the acquisition and related funding. These pro forma results are prepared as if the acquisition had occurred as of the beginning of the periods presented and are not necessarily indicative of the operating results that would have occurred had the acquisition been consummated at that date, nor are they necessarily indicative of future operating results.


	Year Ended
	December 31,

	2005⁽¹⁾			2004

	(In millions, except
	per share amounts)
Revenues	$	4,056		$	5,589
Net loss available to common stockholders		(623	)		(958	)
Basic and diluted loss per share		(0.96	)		(1.50	)


⁽¹⁾	Excludes a $13 million charge or loss of $(0.02) per share for change in control payments triggered at Medicine Bow as a result of the acquisition.

Chaparral and Gemstone. During 2003, we acquired the remaining third party interests in our Chaparral and Gemstone power generation investments for approximately $1 billion and began consolidating them in the first and second quarters of 2003, respectively. We have reflected the results of operations in our income statement for Chaparral as though we acquired it on January 1, 2003 and the results of operations for Gemstone in our income statement since April 1, 2003. Had we acquired Gemstone on January 1, 2003, our net income and loss per share would have been unaffected.


3.	Divestitures


	Sales of Assets and Investments

During 2005, 2004 and 2003, we completed the sale of a number of assets and investments in each of our business segments and corporate operations. The following table summarizes the proceeds from these sales:


		2005		2004		2003

		(In millions)
Pipelines		$	49	$	59	$	145
Exploration and Production			7		24		673
Power			625		884		768
Field Services			657		1,029		753
Corporate			121		16		149

Total continuing⁽¹⁾			1,459		2,012		2,488
Discontinued			577		1,295		808

	Total	$	2,036	$	3,307	$	3,296


⁽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 $35 million, $85 million and $30 million for the years ended December 31, 2005, 2004 and 2003.

The following table summarizes the significant assets sold. See Notes 5 and 21 for a discussion of gains, losses and impairments related to the sales below:


	2005	2004	2003

Pipelines	• Facilities located in the southeastern U.S. • Interest in a gathering system in the western U.S.	• Australian pipelines • Interest in gathering systems	• 2.1% interest in Alliance pipeline • Equity interest in Portland Natural Gas Transmission System • Horsham pipeline in Australia

Exploration and Production	• Miscellaneous domestic natural gas and oil properties	• Brazilian exploration and production acreage	• Natural gas and oil properties in NM, TX, LA, OK and the Gulf of Mexico

Power	• Cedar Brakes I and II • Interest in power plants in Korea, India, England and China • Four domestic power plants • Portion of investment in Intercontinental Exchange • Mohawk River Funding II • Power turbines	• 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

Field Services	• General partner and common unit interests in Enterprise • Interest in Indian Springs natural gas gathering system and processing facility • Interest in Javelina natural gas processing and pipeline assets	• 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, Series B preference units and 50 percent general partnership interests in GulfTerra

Corporate	• Lakeside Technology Center	• Aircraft	• Aircraft • Enerplus Global Energy Management Company and its financial operations • EnCap funds management business and its investments

Discontinued	• Interest in Paraxylene facility • MTBE processing facility • International natural gas and oil properties • South Louisiana gathering and processing assets • Ammonia manufacturing facility	• Natural gas and oil 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

We have also completed or entered into agreements to sell (i) our interests in our remaining Asian power assets (which includes our CEBU and East Asia Utilities power plants in discontinued operations) for $174 million; (ii) substantially all of our interests in our Central and other South American power assets (which includes our Nejapa power plant in discontinued operations) for $164 million; (iii) our interest in a power facility in Hungary for $28 million; (iv) a power turbine for $9 million; and (v) our Macae power facility (included in discontinued operations) for $358 million. We also signed a letter of intent in February 2006 to resolve the arbitration proceedings with COPEL relating to the Araucaria power facility and to sell our interest in the facility to COPEL for $190 million. See Note 16 for a further discussion of these matters.

Discontinued Operations

South Louisiana Gathering and Processing Operations. During the second quarter of 2005, our Board of Directors approved the sale of our south Louisiana gathering and processing assets, which were part of our Field Services segment. In the fourth quarter of 2005, we completed the sale of these assets for net proceeds of approximately $486 million and recorded a pre-tax gain of approximately $394 million.

International Power Operations. During 2005, our Board of Directors approved the sale of our Asian and Central American power asset portfolio, which included our consolidated interests in the Nejapa, CEBU and East Asia Utilities power plants. During 2005, we recognized approximately $166 million of impairment losses, net of minority interest, based on our decision to sell these assets. We expect to complete the sale of our Nejapa, CEBU and East Asia Utilities power plants during 2006.

In March 2006, our Board of Directors approved the sale of our interest in Macae, a wholly owned power plant facility in Brazil. These financial statements and related notes reflect Macae as discontinued operations for all periods presented. On April 27, 2006, we completed the sale of Macae to Petrobras and entered into an agreement fully resolving all matters in dispute with Petrobras. See Note 16 for a discussion of these matters. In addition, we redeemed the outstanding Macae project debt in April 2006. During 2005, we recognized approximately $333 million of impairments as a result of a dispute and indication of value we would receive for the potential sale of the plant.

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, 2005, we have completed the sale of substantially all of these properties for total proceeds of approximately $395 million. During 2005 and 2004, we recognized approximately $5 million and $22 million in losses based on our decision to sell these assets.

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 fair value. As a result, we recognized pre-tax impairment charges during 2003 of approximately $1.5 billion related to certain of 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.

Coal Mining. In 2003, we sold our coal mining operations, which consisted of fifteen active underground and two surface mines located in Kentucky, Virginia and West Virginia. We received sales proceeds of $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.

As of December 31, 2005 and 2004, our assets held for sale (which primarily relate to a natural gas gathering system and processing facility we sold in 2005) and the assets of our discontinued operations (which primarily relate to Macae) were $583 million and $1,395 million and our total liabilities were $422 million and $547 million primarily related to property, plant and equipment and working capital balances related to these facilities. The summarized operating results of our discontinued operations were as follows:


	South
	Louisiana						International
	Gathering						Natural Gas
	and			International			and Oil
	Processing			Power			Production			Petroleum			Coal
	Operations			Operations			Operations			Markets			Mining			Total

	(In millions)
Year Ended December 31, 2005
Revenues	$	292		$	207		$	2		$	125		$	—		$	626
Costs and expenses		(264	)		(216	)		(1	)		(181	)		—			(662	)
Gain (loss) on long-lived assets		394			(510	)		(5	)		7			—			(114	)
Other income		—			13			—			12			—			25
Interest and debt expense		—			(26	)		—			—			—			(26	)

Income (loss) before income taxes	$	422		$	(532	)	$	(4	)	$	(37	)	$	—			(151	)

Income taxes																	99

Income from discontinued operations, net of income taxes																$	(250	)

Year Ended December 31, 2004
Revenues	$	265		$	393		$	31		$	787		$	—		$	1,476
Costs and expenses		(229	)		(225	)		(53	)		(839	)		—			(1,346	)
Loss on long-lived assets		—			(30	)		(22	)		(36	)		—			(88	)
Other income		—			10			—			15			—			25
Interest and debt expense		—			(39	)		1			(3	)		—			(41	)

Income (loss) before income taxes	$	36		$	109		$	(43	)	$	(76	)	$	—			26

Income taxes																	69

Loss from discontinued operations, net of income taxes																$	(43	)

Year Ended December 31, 2003
Revenues	$	246		$	303		$	88		$	5,652		$	27		$	6,316
Costs and expenses		(242	)		(178	)		(129	)		(5,793	)		(13	)		(6,355	)
Loss on long-lived assets		—			—			(89	)		(1,404	)		(9	)		(1,502	)
Other income (expense)		—			12			—			(10	)		1			3
Interest and debt expense		—			(23	)		4			(11	)		—			(30	)

Income (loss) before income taxes	$	4		$	114		$	(126	)	$	(1,566	)	$	6			(1,568	)

Income taxes																	(356	)

Loss from discontinued operations, net of income taxes																$	(1,212	)


4.	Restructuring and Other Charges

The discussion below provides additional details of certain costs incurred in connection with our ongoing liquidity enhancement and cost reduction efforts in 2003, 2004, and 2005 and in conjunction with our Western Energy Settlement. These charges were recorded as part of operations and maintenance expense.

Employee severance, retention and transition costs. Employee severance costs were not significant in 2005. During 2004, we eliminated approximately 1,900 full-time positions from our continuing businesses and approximately 1,200 positions related to businesses we discontinued. As a result, we incurred approximately $38 million of employee severance costs primarily related to our Exploration and Production segment and

corporate operations. Additionally, during 2003, we eliminated approximately 900 full-time positions from our continuing businesses and approximately 1,800 positions related to businesses we discontinued and incurred approximately $76 million of employee severance costs, primarily related to our Marketing and Trading segment and corporate operations. As of December 31, 2005, substantially all of the total employee severance, retention and transition costs had been paid.

Office relocation and consolidation. During 2004, we announced that we would consolidate our Houston-based operations into one location and incurred $80 million of charges to record the discounted liability, net of estimated sub-lease rentals, for our obligations under leases for space we no longer use. In 2005, we vacated our remaining leased space, signed a termination agreement on the lease and recorded additional charges of $27 million related to these actions. The costs associated with this office relocation and consolidation have been charged to corporate operations. Actual moving expenses related to the relocation were insignificant and were expensed in the periods that they were incurred. As of December 31, 2005, our remaining liability associated with this consolidation and relocation was $97 million.

Western Energy Settlement. During 2003 and 2005, we incurred charges in operations and maintenance expense related to the final resolution of our Western Energy Settlement of $104 million and $59 million. Final payments under this settlement were made in early 2005.

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 and were charged to corporate operations.

5. (Gain) Loss on Long-Lived Assets

Our (gain) 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 (gain) loss on long-lived assets was as follows:


			2005			2004			2003

			(In millions)
Net realized (gain) loss			$	1		$	(16	)	$	69

Asset impairments
	Power
		Brazilian assets⁽¹⁾		—			183			—
		Domestic assets and restructured power contract entities ⁽²⁾		—			397			147
		Turbines⁽²⁾		18			1			33
	Pipelines
		Pipeline development projects⁽³⁾		46			—			—
	Field Services
		Goodwill impairment⁽⁴⁾		—			480			—
		Indian Springs processing assets⁽²⁾		—			13			—
		South Texas processing assets⁽²⁾		—			—			167
		Other		9			10			4
	Exploration and Production
		Other		—			8			10
	Corporate
		Telecommunications assets⁽²⁾		—			—			396
		Other		—			1			34

		Total asset impairments		73			1,093			791

	Loss on long-lived assets			74			1,077			860
	(Gain) loss on sale of investments in unconsolidated affiliates, net of impairments⁽⁵⁾			(91	)		(124	)		176

	(Gain) loss on assets and investments		$	(17	)	$	953		$	1,036


⁽¹⁾	These assets were impaired as a result of negotiations associated with the power contracts of these plants.
⁽²⁾	We adjusted the carrying value of these assets to their estimated fair value, less cost to sell.
⁽³⁾	This impairment resulted from our decision to discontinue development of several pipeline expansion projects.
⁽⁴⁾	This impairment resulted from the sale of substantially all of our interests in GulfTerra, as well as the sale of our processing assets in south Texas to affiliates of Enterprise in 2004 (see Note 21).
⁽⁵⁾	See Note 21 for a further description of these gains and losses.

For additional asset impairments on our discontinued operations and investments in unconsolidated affiliates, see Notes 3 and 21. 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:


			2005		2004		2003

			(In millions)
Other Income
	Interest income		$	126	$	89	$	81
	Allowance for funds used during construction			31		23		19
	Development, management and administrative services fees on power projects from affiliates			11		14		12
	Re-application of SFAS No. 71 (CIG and WIC)			—		—		18
	Foreign currency gain			36		15		9
	Gain on sale of cost basis investments			40		—		7
	Dividend income			19		—		6
	Other			26		41		39

		Total	$	289	$	182	$	191

Other Expenses
	Foreign currency losses		$	—	$	26	$	112
	Loss on early extinguishment of debt			29		12		37
	Loss on exchange of equity security units			—		—		12
	Minority interest in consolidated subsidiaries			4		40		3
	Other			17		20		38

		Total	$	50	$	98	$	202

7. Income Taxes

Pretax Income (Loss) and Income Tax Expense (Benefit). The tables below show our pretax income (loss) from continuing operations and the components of income tax expense (benefit) for each of the years ended December 31:


				2005			2004			2003

				(In millions)
Pretax Income (Loss)
	U.S.			$	(638	)	$	(751	)	$	(1,326	)
	Foreign				35			(196	)		134

				$	(603	)	$	(947	)	$	(1,192	)

Components of Income Tax Expense (Benefit)
	Current
		Federal		$	(10	)	$	(15	)	$	35
		State			(35	)		36			57
		Foreign			22			8			(2	)

					(23	)		29			90

	Deferred
		Federal			(297	)		(66	)		(566	)
		State			67			(7	)		(54	)
		Foreign			2			1			—

					(228	)		(72	)		(620	)

			Total income taxes	$	(251	)	$	(43	)	$	(530	)

Effective Tax Rate Reconciliation. 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:


		2005			2004			2003

		(In millions, except rates)
Income taxes at the statutory federal rate of 35%		$	(211	)	$	(331	)	$	(417	)
Increase (decrease)
	Sales and write-offs of foreign investments		(7	)		14			(53	)
	Valuation allowances		34			18			(57	)
	Foreign income taxed at different rates		75			133			(29	)
	Earnings from unconsolidated affiliates where we anticipate receiving dividends		(37	)		(18	)		(13	)
	Audit settlements⁽¹⁾		(58	)		—			—
	Non-deductible goodwill impairments		—			139			29
	Non-taxable medicare reimbursements		(25	)		—			—
	Other		(22	)		2			10

Income taxes		$	(251	)	$	(43	)	$	(530	)

Effective tax rate			42	%		5	%		44	%


⁽¹⁾	We finalized The Coastal Corporation’s IRS tax audits for years prior to 1997, and as a result, recorded a tax benefit of approximately $58 million in 2005.

Deferred Tax Assets and Liabilities. The following are the components of our net deferred tax liability related to continuing operations as of December 31:


				2005			2004

				(In millions)
Deferred tax liabilities
	Property, plant and equipment			$	3,328		$	2,521
	Investments in unconsolidated affiliates				192			410
	Regulatory and other assets				321			324

			Total deferred tax liability		3,841			3,255

Deferred tax assets
	Net operating loss and tax credit carryovers
		Federal			1,101			1,194
		State			204			174
		Foreign			49			29
	Environmental liability				159			174
	Price risk management activities				573			—	⁽¹⁾
	Legal and other reserves				280			124
	Other				601			783
	Valuation allowance				(107	)		(51	)

			Total deferred tax asset		2,860			2,427

Net deferred tax liability				$	981		$	828


⁽¹⁾	As of December 31, 2004, we had a net deferred tax liability associated with our price risk management activities which was included as part of Regulatory and other assets above.

Prior to 2004, we had not recorded U.S. deferred tax assets or liabilities on book versus tax basis differences for a substantial portion of our international investments based on our intent to indefinitely reinvest earnings from these investments outside the U.S. However, based on sales negotiations on certain of our Asian and Central American power assets, we have received or expect to receive these sales proceeds within the U.S.

During the years ended December 31, 2005 and 2004, our effective tax rate was impacted upon recording U.S. deferred tax assets and liabilities on book versus tax basis differences in these investments based on the status of these negotiations. We also recorded U.S. deferred tax benefits on the sale of a power asset in India. As of December 31, 2005 and 2004, we have U.S. deferred tax assets of $103 million and $6 million and U.S. deferred tax liabilities of $23 million and $39 million related to these investments.

Cumulative undistributed earnings from the remainder of our foreign subsidiaries and foreign corporate joint ventures (excluding our Asian and Central American 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, and an estimate of the taxes if earnings were to be repatriated is not practical. At December 31, 2005, the portion of the cumulative undistributed earnings from these investments on which we have not recorded U.S. income taxes was approximately $121 million. 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.

Tax Credit and NOL Carryovers. As of December 31, 2005, we have U.S. federal alternative minimum tax credits of $303 million that carryover indefinitely and capital loss carryovers of $11 million for which the carryover period ends in 2008. The table below presents the details of our federal and state net operating loss carryover periods as of December 31, 2005:


	Carryover Period

	2006		2007-2010		2011-2015		2016-2025		Total

	(In millions)
U.S. federal net operating loss	$	—	$	10	$	15	$	2,745	$	2,770
State net operating loss		126		699		553		1,236		2,614

We also had $225 million of foreign net operating loss carryovers of which $192 million carryover indefinitely, $30 million carryover through 2007, and the remainder carryover through 2008 and 2009. 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.

Valuation Allowances. Deferred tax assets are recorded on net operating losses and temporary differences in the book and tax basis of assets and liabilities expected to produce tax deductions in future periods. The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions during periods in which those temporary differences or net operating losses are deductible. In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized. We believe it is more likely than not that we will realize the benefit of our deferred tax assets, net of existing valuation allowances, due to the effect of future reversals of existing taxable temporary differences primarily related to depreciation.

During 2005, we recorded a state valuation allowance on deferred state tax assets generated in 2005, and recorded additional valuation allowances on existing deferred state tax assets due to changes in expected revenue allocations for future periods. In addition, we recorded foreign deferred tax assets on our Macae project (which is anticipated to be sold in 2006) from the generation of tax loss carryforwards and differences in the book and tax basis of fixed assets due to the impairment of the project. At this time, we recorded a full valuation allowance of $51 million, which is included in discontinued operations, on these assets as we do not expect to generate sufficient future taxable income to realize them.

Other Tax Matters. The IRS has audited The Coastal Corporation’s 1998-2000 tax years and El Paso Corporation’s 2001 and 2002 tax years, and these audits are pending finalization with the IRS Appeals Office. We anticipate that these audits will be finalized in either 2006 or 2007. In addition, the IRS is currently auditing El Paso’s 2003 and 2004 tax years. We have recorded a liability for tax contingencies associated with these audits, as well as for proceedings and examinations with other taxing authorities, which management believes is adequate. As these matters are finalized, we may be required to adjust our liability which could significantly increase or decrease our income tax expense in future periods.

8. Earnings Per Share

We incurred losses from continuing operations during the three years ended December 31, 2005. Accordingly, we excluded a number of securities for the years ended December 2005, 2004, and 2003 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 2005 we excluded our convertible preferred stock, which has conversion features discussed in Note 18, and in 2003, we excluded shares related to our remaining stock obligation under the Western Energy Settlement. For a further discussion of these instruments, see Notes 14 and 19.

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, 2005 and 2004.


	2005						2004

	Carrying						Carrying
	Amount			Fair Value			Amount		Fair Value

	(In millions)
Long-term financing obligations, including current maturities⁽¹⁾	$	18,009		$	18,453		$	18,869	$	19,509
Commodity-based price risk management derivatives		(1,416	)		(1,416	)		68		68
Interest rate and foreign currency derivatives		2			2			239		239
Investments		61			61			47		47


⁽¹⁾	Excludes Macae project debt, which was included in liabilities related to discontinued operations.

As of December 31, 2005 and 2004, 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. Our investments primarily relate to available for sale securities and cost basis investments.

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, 2005 and 2004. In the table, derivatives designated as hedges consist of instruments used to hedge our natural gas and oil production. Other commodity-based derivative contracts relate to derivative contracts not designated as hedges, such as options, swaps, tolling agreements (assigned to a third party in 2005) and other natural gas and power purchase and supply contracts, our historical energy trading activities and our power contract restructuring activities (which were fully disposed of in 2004 and 2005). Finally, interest rate and foreign currency derivatives consist of swaps that are primarily designated as hedges of our interest rate and foreign currency risk on long-term debt.


			2005			2004

			(In millions)
Net assets (liabilities)
	Derivatives designated as hedges		$	(653	)	$	(536	)
	Other commodity-based derivative contracts⁽¹⁾			(763	)		604

		Total commodity-based derivatives		(1,416	)		68
	Interest rate and foreign currency derivatives⁽²⁾			2			239

		Net assets (liabilities) from price risk management activities⁽³⁾	$	(1,414	)	$	307


⁽¹⁾	Decrease is due primarily to the sale or assignment of a number of derivative contracts and significant changes in natural gas and oil prices during 2005.
⁽²⁾	Decrease is due to settlement of hedge contracts upon repurchase of related debt as discussed below.
⁽³⁾	Included in both current and non-current assets and liabilities 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. Historically, we used commodity prices from market-based sources such as the New York Mercantile Exchange for forward pricing data within two years. For forecasted settlement prices beyond two years, we used a combination of commodity prices from market-based sources and other independent pricing sources to develop price curves. The curves were then used to estimate the value of settlements in future periods based on the contractual settlement quantities and dates. Finally, we discounted these estimated settlement values using a LIBOR curve for the majority of our derivative contracts or by using an adjusted risk-free rate for our restructured power contracts. Additionally, contracts denominated in foreign currencies were converted to U.S. dollars using market-based, foreign exchange spot rates.

Effective April 1, 2005, we began using new forward pricing data provided by Platts Research and Consulting, our independent pricing source, due to their decision to discontinue the publication of the pricing data they had provided to us in prior periods. In addition, due to the nature of the new forward pricing data, we extended the use of that data over the entire contractual term of our derivative contracts. Prior to April 1, 2005, we only used Platts’ pricing data to value our derivative contracts beyond two years. Based on our analysis, the overall impact of this change in estimate was not material to our financial statements.

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.

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 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. 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 may designate the derivative as either a cash flow hedge or a fair value hedge. Our hedges of our interest rate and 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 then recognized in earnings when the hedged transactions occur. The ineffective portion of a cash flow hedge’s change in value, if any, is recognized immediately in earnings as a component of operating revenues or interest and debt expense 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 regularly 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 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 as well as fluctuations in foreign currency and interest rates with the objective of realizing a fixed cash flow stream from these activities. A summary of the impacts of our cash flow hedges included in

accumulated other comprehensive income (loss), net of income taxes, as of December 31, 2005 and 2004 follows.


		Accumulated
		Other
		Comprehensive						Estimated
		Income (Loss)						Income (Loss)			Final
								Reclassification			Termination
		2005			2004			in 2006⁽¹⁾			Year

		(In millions)
Commodity cash flow hedges
	Held by consolidated entities⁽²⁾	$	(285	)	$	54		$	(220	)		2012
	Held by unconsolidated affiliates		(7	)		(8	)		2			2013

	Total commodity cash flow hedges		(292	)		46			(218	)
Interest rate and foreign currency cash flow hedges
	Fixed rate⁽³⁾		2			4			—			2015
	Undesignated		(4	)		(8	)		—			2009

	Total foreign currency cash flow hedges		(2	)		(4	)		—

	Total⁽⁴⁾	$	(294	)	$	42		$	(218	)


⁽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⁾	We have a derivative that hedges a portion of the production owned by UnoPaso, a wholly-owned subsidiary that owns natural gas and oil properties in Brazil. As a result of the earlier than expected payout of certain of UnoPaso’s natural gas and oil properties, which will reduce our interest in the properties and related anticipated production volumes, we recorded an $11 million loss in the third quarter of 2005 related to the elimination of the accumulated other comprehensive loss associated with this hedge and reclassified the hedge as an other commodity-based derivative contract.
⁽³⁾	In March 2005, we repurchased approximately €528 million of debt, of which € 375 million was hedged with interest rate and foreign currency derivatives. As a result of the repurchase, we removed the hedging designation on these derivatives and settled substantially all of the contracts. We recorded a gain of approximately $2 million during the first quarter of 2005 upon the reversal of the related accumulated other comprehensive income associated with these derivatives.
⁽⁴⁾	Accumulated other comprehensive income (loss) also includes: a) $(4) million and $5 million of net cumulative foreign currency translation adjustments as of December 31, 2005 and 2004; b) $(49) million and $(46) million of additional minimum pension liability as of December 31, 2005 and 2004; and c) $15 million of unrealized gains related to an available for sale security as of December 31, 2005. 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 reclassified this amount to derivatives designated as cash flow hedges, beginning in the fourth quarter of 2004.

For the years ended December 31, 2005, 2004 and 2003, we recognized net losses of $5 million, $1 million and $2 million, net of income taxes, in our loss from continuing operations related to the ineffective portion of our commodity cash flow hedges. We did not record any ineffectiveness related to our interest rate or foreign currency cash flow hedges in 2003, 2004 and 2005.

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, 2005 and 2004, these derivatives had a net fair value loss of $7 million and gain of $117 million. Specifically, we had derivatives with fair value losses of $30 million and $20 million as of December 31, 2005 and 2004, that converted the interest rate on $440 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 $23 million and $137 million as of December 31, 2005 and 2004, that converted approximately €350 million and € 450 million of our debt to $402 million and $511 million. These derivatives also converted the interest rate on this debt to a floating weighted average interest rate of LIBOR plus 4.2% as of December 31, 2005, and LIBOR plus 3.9% as of December 31, 2004. We have recorded the fair value of those derivatives as a component of long-term debt and the related accrued interest.

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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 settled, these derivative 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. Additionally, they include derivatives related to our historical power contract restructuring activities and other derivative contracts not designated as hedges, including our production-related option and swap contracts held by our Marketing and Trading segment.

During 2001 and 2002, we conducted power contract restructuring activities that involved amending or terminating power purchase contracts at existing power facilities. 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 during 2005, we disposed of our remaining historical restructured power contracts. Specifically, during 2005, we sold or assigned derivative contracts with a net fair value of $376 million in conjunction with the sales of Cedar Brakes I and II and Mohawk River Funding II entities. See Note 3 for a discussion of these sales, which include the sales of UCF, Cedar Brakes I and II and our other power restructuring entities that owned derivative contracts.

Additionally, during 2005, we entered into agreements to assign a number of our other derivative contracts not designated as hedges. Specifically, we (i) completed the assignment of our liability under the Cordova tolling agreement for which we paid $177 million and (ii) entered into an agreement to assign the majority of our power derivative assets to Morgan Stanley. This assignment requires the consent of existing third parties before the contracts can be transferred to Morgan Stanley. Until the assignment is finalized, we entered into offsetting liability contracts with Morgan Stanley to eliminate the commodity price risk associated with the contracts being assigned. We received total proceeds of $442 million to enter into these offsetting contracts and deposited a similar amount of cash margin. The amount received approximated the value we would have received if we had directly sold our power derivative assets. We expect to complete this assignment to Morgan Stanley in the first half of 2006.


	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 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

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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 derivative counterparties in which we had net asset exposure as of December 31, 2005 and 2004.


		Net Derivative Instrument Asset Exposure

					Below			Not
Counterparty		Investment Grade⁽¹⁾			Investment Grade⁽¹⁾			Rated⁽¹⁾			Total

		(In millions)
December 31, 2005
Energy marketers		$	554		$	110		$	—		$	664
Natural gas and electric utilities			6			—			134			140
Commodity exchanges			515			—			—			515
Other			45			—			1			46

	Net financial instrument assets ⁽²⁾		1,120			110			135			1,365
	Collateral held by us		(831	)		(96	)		(68	)		(995	)

	Net exposure from derivative assets	$	289		$	14		$	67		$	370


		Net Derivative 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
Commodity exchanges			242			—			—			242
Other			3			—			7			10

	Net financial instrument assets ⁽²⁾		1,109			44			133			1,286
	Collateral held by us		(349	)		(39	)		(81	)		(469	)

	Net exposure from derivative assets	$	760		$	5		$	52		$	817


⁽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.

We have approximately 95 counterparties as of December 31, 2005, 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, 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.

As of December 31, 2005, two energy marketers, Constellation Energy Commodities Group, Inc. and Duke Energy Trading and Marketing LLC, comprised 28 percent and 18 percent of our net financial instrument asset exposure. As of December 31, 2004, one electric utility customer, Public Service Electric and

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Gas Company (PSEG), comprised 42 percent of our net financial instrument asset exposure; however, this exposure to PSEG was eliminated with the sale of our interests in Cedar Brakes I and II in 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. Regulatory Assets and Liabilities

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


Description			2005		2004

			(In millions)
Current regulatory assets			$	4	$	3

Non-current regulatory assets
	Grossed-up deferred taxes on capitalized funds used during construction			96		85
	Postretirement benefits			25		30
	Unamortized net loss on reacquired debt			20		23
	Under-collected state income tax			7		7
	Other			16		10

		Total non-current regulatory assets		164		155

		Total regulatory assets	$	168	$	158

Current regulatory liabilities			$	9	$	9

Non-current regulatory liabilities
	Environmental liability			110		97
	Cost of removal of offshore assets			48		50
	Property and plant depreciation			41		35
	Postretirement benefits			16		13
	Plant regulatory liability			11		11
	Excess deferred income taxes			8		11
	Other			8		11

		Total non-current regulatory liabilities		242		228

		Total regulatory liabilities	$	251	$	237

12. 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:


			2005		2004

			(In millions)
Other current assets
	Prepaid expenses		$	89	$	118
	Restricted cash (Note 1)			94		103
	Inventory			140		155
	Other			25		46

		Total	$	348	$	422

Other non-current assets
	Pension assets (Note 17)		$	886	$	933
	Notes receivable from affiliates			263		287
	Restricted cash (Note 1)			168		180

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			2005		2004

			(In millions)
	Unamortized debt expenses			171		183
	Regulatory assets (Note 11)			164		155
	Long-term receivables			410		316
	Assets of discontinued operations (Note 3)			353		1,007
	Other			197		262

		Total	$	2,259	$	3,323

Other current liabilities
	Accrued taxes, other than income		$	108	$	134
	Western Energy Settlement			—		44
	Income taxes			61		77
	Environmental, legal and rate reserves (Note 16)			181		84
	Deposits			31		39
	Other postretirement benefits (Note 17)			35		38
	Accrued lease obligations			43		4
	Asset retirement obligations (Note 1)			33		28
	Dividends payable			35		25
	Accrued liabilities			36		74
	Other			124		175

		Total	$	687	$	722

Other non-current liabilities
	Environmental and legal reserves (Note 16)		$	1,028	$	763
	Western Energy Settlement			—		351
	Other postretirement and employment benefits (Note 17)			224		249
	Regulatory liabilities (Note 11)			242		228
	Asset retirement obligations (Note 1)			194		244
	Other deferred credits			186		126
	Accrued lease obligations			77		126
	Insurance reserves			132		125
	Liabilities related to discontinued operations (Note 3)			2		97
	Other			188		185

		Total	$	2,273	$	2,494

13. Property, Plant and Equipment

At December 31, 2005 and 2004, we had approximately $1.1 billion and $0.8 billion of construction work-in-progress included in our property, plant and equipment.

As of December 31, 2005 and 2004, 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 $1.4 billion and $1.3 billion at December 31, 2005 and 2004. These excess costs are being depreciated over the life of the pipeline assets we assigned the costs to, and our related depreciation expense for the years ended December 31, 2005, 2004, and 2003 was approximately $76 million, $76 million and $74 million. We do not currently earn a return on these excess purchase costs from our rate payers.

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14. Debt, Other Financing Obligations and Other Credit Facilities


		2005		2004

		(In millions)
Short-term financing obligations, including current maturities⁽¹⁾		$	986	$	635
Long-term financing obligations			17,023		18,241

	Total	$	18,009	$	18,876


⁽¹⁾	Excludes Macae project debt of $225 million in 2005 and $320 million in 2004, which is reported in liabilities related to discontinued operations.

A summary of changes in our debt is as follows (in millions):


Debt obligations as of December 31, 2004		$	18,876
Principal amounts borrowed			1,638
Repayment/retirement of principal			(1,809	)
Sale of entities⁽¹⁾			(575	)
Other			(121	)

	Total debt as of December 31, 2005	$	18,009


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

Short-Term Financing Obligations

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


	2005		2004

	(In millions)
Current maturities of long-term debt and other financing obligations	$	986	$	628
Short-term financing obligation		—		7

	$	986	$	635

Long-Term Financing Obligations

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


			2005			2004

			(In millions)
Long-term debt
	ANR Pipeline Company
		Debentures and notes, 7.0% through 9.625%, due 2010 through 2025	$	732		$	800
		Notes, 13.75% due 2010		12			12
	Colorado Interstate Gas Company
		Senior debentures, 10.0% and 6.85%, due 2005 and 2037		100			280
		Senior notes, 5.95% and 6.80%, due 2015		600			—
	El Paso CGP Company, L.L.C.⁽¹⁾
		Notes, 6.5% through 7.75%, due 2006 through 2010		—			930
		Senior debentures, 6.375% through 10.75%, due 2008 through 2037		—			1,357
	El Paso Corporation
		Senior debentures, 6.375% through 10.75%, due 2008 through 2037		166	⁽¹⁾		—
		Senior notes, 5.75% through 10.75%, due 2006 through 2037		3,439	⁽¹⁾		1,956
		Equity security units, 6.14% due 2007		—			272
		Notes, 6.50% through 7.875%, due 2005 through 2018		1,854	⁽¹⁾		1,952
		Medium-term notes, 6.95% through 9.0%, due 2005 through 2032		2,735			2,784
		Zero coupon convertible debentures due 2021		611			822
		$1.25 billion term loan, LIBOR plus 2.75% due 2009		1,225			1,245

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				2005		2004

				(In millions)
	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 Exploration & Production Company
		Senior notes, 7.75%, due 2013			1,200		1,200
		Revolving credit facility, LIBOR plus 1.875% due 2010			500		—
	Power
		Non-recourse senior notes, 8.5% and 9.875%, due 2013 and 2014			—		666
		Recourse notes, 7.27% and 8.5%, due 2016			—		40
	Southern Natural Gas Company
		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				325		137

					17,440		18,394

Other financing obligations
	Capital Trust I				325		325
	Coastal Finance I				300		300

					625		625

			Subtotal		18,065		19,019
Less:
	Unamortized discount and premium on long-term debt				56		150
	Current maturities				986		628

			Total long-term financing obligations, less current maturities	$	17,023	$	18,241


⁽¹⁾	Approximately $2.3 billion of El Paso CGP Company, L.L.C. debt was exchanged for El Paso debt or assumed by El Paso in December 2005.

During 2005 and to date in 2006, we had the following changes in our long-term financing obligations:


							Cash
Company		Type	Interest Rate		Book Value		Received/Paid

					(In millions)
Issuances
	Colorado Interstate Gas Company	Senior notes due 2015		5.95%	$	200	$	197
	Cheyenne Plains Gas Pipeline Company⁽¹⁾	Non-recourse term loan due 2015		Variable		266		261
	El Paso Exploration & Production Company	Revolving credit facility due 2010		LIBOR +1.875%		500		495
	El Paso⁽²⁾	Senior notes due 2007		7.625%		272		272
	Colorado Interstate Gas Company	Senior notes due 2015		6.8%		400		395

		Increases through December 31, 2005			$	1,638	$	1,620

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							Cash
Company		Type	Interest Rate		Book Value		Received/Paid

					(In millions)
Repayments, repurchases, retirements and other
	El Paso	Zero coupon debentures⁽³⁾		—	$	236	$	237
	El Paso	Notes		6.88%		167		167
	Cedar Brakes I⁽⁴⁾	Non-recourse senior notes		8.5%		241		15
	Cedar Brakes II⁽⁴⁾	Non-recourse senior notes		9.88%		334		14
	Mohawk River Funding II ⁽⁴⁾	Non-recourse note		9.0%		37		8
	El Paso⁽⁵⁾	Euro notes		5.75%		695		722
	El Paso⁽²⁾	Senior notes due 2007		6.14%		272		—
	Colorado Interstate Gas Company	Senior debentures		10.00%		180		180
	Other	Long-term debt		Various		343		222

		Decreases through December 31, 2005			$	2,505	$	1,565
	Coastal Finance I	Trust originated preferred securities		8.375%		300		300
	El Paso	Zero coupon debentures⁽³⁾		—		603		603
	Other	Long-term debt		Various		2		2

		Decreases through February 28, 2006			$	3,410	$	2,470


⁽¹⁾	In addition to the borrowing, we have an associated letter of credit facility for $12 million, under which we issued $6 million of letters of credit in May 2005. We also concurrently entered into swaps to convert the variable interest rate on approximately $213 million of this debt to a current fixed rate of 5.94%.
⁽²⁾	In July 2005, we remarketed $272 million of notes which originally formed a portion of our 9.0% equity security units. Existing note holders utilized proceeds from the remarketing to satisfy their obligation under the equity security units to purchase common stock which had the effect of exchanging debt for equity. We have reflected this transaction as a non-cash financing transaction and the issuance of the new remarketed notes as a financing cash inflow.
⁽³⁾	This security has a yield-to-maturity of approximately 4%.
⁽⁴⁾	Prior to the sale of Cedar Brakes I and II, and Mohawk River Funding II, we made $37 million of scheduled principal repayments. Upon the sale of these entities, the remaining balance of $575 million was eliminated.
⁽⁵⁾	We recorded a $26 million loss on the early extinguishment of this debt.

We recorded accretion expense on our zero coupon bonds of $25 million and $36 million during the years ended December 31, 2005 and 2004. These amounts are added to the principal balance each period and are included in our long-term debt. We account for redemption of zero coupon debentures as a financing activity in our statement of cash flows, which included this accretion. During 2005, we redeemed $236 million of our zero coupon debentures of which $34 million represented increased principal due to the accretion of interest on the debentures.

Debt Maturities

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):


2006⁽¹⁾		$	986
2007			781
2008			676
2009			2,479
2010			2,058
Thereafter			11,085

	Total long-term financing obligations, including current maturities	$	18,065


⁽¹⁾	Excludes Macae project debt of $225 million in 2005, which is reported in liabilities related to discontinued operations.

Included in 2006 maturities are approximately $0.6 billion of zero coupon debentures, which the holders required us to redeem in February 2006 for cash. Additionally, we have debt of approximately $600 million that is redeemable by holders in 2007, prior to its stated maturity, which is included in the “Thereafter” amount.

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In addition to the debt we may be required to redeem prior to its maturity, we also have a number of our debt obligations that are callable by us prior to their stated maturity date. At this time, we have $12.1 billion of debt obligations callable in 2006 and an additional $0.6 billion callable in 2007 and thereafter. To the extent we decide to redeem any of this debt, certain obligations will require us to pay a make whole premium.

Credit Facilities

In November 2004, we entered into a $3 billion credit agreement consisting 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. Our subsidiaries, ANR, CIG, EPNG and TGP are eligible borrowers under this credit agreement. Additionally, El Paso and certain of its subsidiaries have guaranteed borrowings under this credit agreement, which is collateralized by our stock ownership in ANR, CIG, ANR Storage Company, EPNG, Southern Gas Storage Company and TGP.

As of December 31, 2005, we had $1.23 billion outstanding under the term loan and had utilized approximately all of the $750 million letter of credit facility and approximately all 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 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 $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.

In August 2005, our subsidiary EEPC entered into a $500 million five-year revolving credit facility bearing interest at LIBOR plus 1.875%. Under the facility, we borrowed $500 million, which was used to partially fund the acquisition of Medicine Bow. The facility can be utilized for funded borrowings or for the issuance of letters of credit and is collateralized by certain EEPC natural gas and oil production properties.

In November 2005, we entered into a $400 million revolving borrowing base credit agreement collateralized by natural gas and oil production properties owned by one of our subsidiaries, which is also a co-borrower. Under the agreement we have initial borrowing availability of $300 million. While we have not drawn any amounts under this credit facility it can be used for revolving credit loans or for the issuance of letters of credit and will mature in May 2006. If fully drawn, the interest rate on this facility would be LIBOR plus 2.50%.


	Restrictive Covenants

$3 billion revolving credit facility. Our restrictive covenants under the $3 billion revolving credit facility include restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on the sales of assets, dividend restrictions, cross default, cross-acceleration and prepayment of debt provisions. A breach of any of these covenants could result in acceleration of our debt and other financial obligations and that of our subsidiaries. Under our 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 credit agreement), shall not exceed 6.25 to 1.0 at any time on or after September 30, 2005, and prior to June 30, 2006, and 6.0 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 credit agreement), to interest expense plus dividends paid shall not be less than 1.6 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 1.8 to 1.0 on or after March 31, 2007, until maturity;

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	(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 credit agreement), for that particular company to exceed 5.0 to 1.0;

	(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.

$500 million credit facility. The availability of borrowings under this facility is subject to various conditions. The financial coverage ratio under the facility requires that EEPC’s EBITDA (as defined in the facility) to interest expense not be less than 2.0 to 1.0, EEPC’s debt to EBITDA must not be greater than 4.5 to 1.0 until September 30, 2006, and 4.0 to 1.0 thereafter, and EEPC’s Collateral Coverage Ratio (as defined in the facility) must be greater than 1.5 to 1.0.

$400 million credit agreement. The availability of borrowings under this facility is subject to various conditions. One of the more restrictive new covenants of this facility is the requirement to maintain a Collateral Coverage Ratio (as defined in the facility) of at least 1.5 to 1.0.

Other Restrictions and Provisions. 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 affiliates with similar covenants as the above facilities.

Our most restrictive acceleration provision is $5 million and is associated with the indenture of one of our subsidiaries. This indenture states that should an event of default occur resulting in the acceleration of other debt obligations in excess of $5 million, the long-term debt obligation containing that provision could be accelerated. The acceleration of our debt would adversely affect our liquidity position and in turn, our financial condition.

Other Financing Arrangements

Capital Trusts. El Paso Energy Capital Trust I (Trust I), is a wholly owned business trust formed in March 1998. Trust I issued 6.5 million of 4.75 percent trust convertible preferred securities in a public offering for $325 million. 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. Trust I’s sole source of income is interest earned on these debentures. This interest income is used to pay distributions on the preferred securities. We also have two wholly owned business trusts, El Paso Energy Capital Trust II and III (Trust II and III), under which we have not issued securities. We provide a full and unconditional guarantee of Trust I’s preferred securities, and would provide the same guarantee if securities were issued under Trust II and III.

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 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). We have classified these securities as long-term debt and we have the right to redeem these securities at any time.

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Coastal Finance I. Coastal Finance I is an indirect wholly owned business trust formed in May 1998. Coastal Finance I issued in a public offering 12 million mandatory redemption preferred securities for $300 million. Coastal Finance I held subordinated debt securities issued by our wholly owned subsidiary, El Paso CGP, L.L.C., that it purchased with the proceeds of the preferred securities offering. Cumulative quarterly distributions were being paid on the preferred securities at an annual rate of 8.375 percent of the liquidation amount of $25 per preferred security. On February 8, 2006, the $300 million of outstanding preferred securities were redeemed.

Non-Recourse Project Financings. Many of our subsidiaries and investments have debt obligations related to their costs of construction or acquisition. Several of our projects have experienced events that have either constituted or could constitute an event of default under the loan agreements. Among other projects, our consolidated Macae project in Brazil, which is reported in our liabilities related to discontinued operations, and our Berkshire project have been either issued a notice of default or experienced an event of default. Our outstanding debt at our consolidated Macae project is $225 million at December 31, 2005. This debt (as well as other project financing debt) is recourse only to the project company and assets (i.e. without recourse to El Paso). We do not believe any of these defaults, or other events that have led to or could lead to events of default at other projects, will have a material effect on us or our subsidiaries’ financial statements based on the amounts we have recorded on our balance sheet for these projects and/or the current status of negotiations relating to these projects (for a further discussion, see Notes 16 and 21).

Letters of Credit

We enter into letters of credit in the ordinary course of our operating activities as well as periodically in conjunction with the sales of assets or businesses. As of December 31, 2005, we had outstanding letters of credit of approximately $2.0 billion, of which $1.7 billion were issued under our credit agreement. Included in this amount is $1.2 billion of letters of credit securing our recorded obligations related to price risk management activities and $0.2 billion related to Macae which is included in discontinued operations.

15. Preferred Interests of Consolidated Subsidiaries

In the past, we entered into transactions accomplished through the sale of preferred interests in consolidated subsidiaries. During 2003, approximately $3 billion of these preferred interests were redeemed, reclassified to long-term debt or eliminated through various actions. In May 2005, we redeemed $300 million of 8.25% Series A cumulative preferred stock of our subsidiary, El Paso Tennessee Pipeline Co.


16.	Commitments and Contingencies

Legal Proceedings

Shareholder/ Derivative/ ERISA Litigation


	Shareholder Litigation. Twenty-eight purported shareholder class action lawsuits have been pending since 2002 and are consolidated in federal court in Houston, Texas. This consolidated lawsuit, which alleges violations of federal securities laws against us and several of our current and former officers and directors, includes allegations regarding the accuracy or completeness of press releases and other public statements made during the class period from 2000 through early 2004 related to alleged wash trades, mark-to-market accounting, off-balance sheet debt, the overstatement of natural gas and oil reserves and manipulation of the California energy market. Formal discovery in the consolidated lawsuit is currently stayed. The Court has ordered the parties to mediate this case in April 2006.

	Derivative Litigation. Since 2002, six shareholder derivative actions have also been filed. Two of these actions were filed in federal court in Houston, two were filed in state court in Houston, and two were filed in Delaware Chancery Court. Only three of these actions remain following consolidation and dismissal of the other cases.


	•	The Houston federal court cases: The first federal court case was filed in 2002 and the second was filed in 2004. The 2002 federal court case generally alleges the same claims pled in the consolidated shareholder class action described above, with the exception that there are no

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		allegations related to the overstatement of natural gas and oil reserves. The 2004 federal court case includes allegations related to the overstatement of natural gas and oil reserves, in addition to the allegations alleged in the 2002 federal court case. The two federal court actions in Houston are both currently stayed.

	•	The Houston state court cases: The two state court actions in Houston have been consolidated. The plaintiffs in those cases originally alleged that the manipulation of California gas prices exposed us to claims of antitrust conspiracy, FERC penalties and erosion of share value. The plaintiffs in the consolidated state court case recently amended their petition to add claims of unjust enrichment of certain former executives allegedly attributable to round trip trading and restructuring of energy contracts and breach of fiduciary duty claims for failure to recover 2001 compensation paid to certain officers and related to the overstatement of natural gas and oil reserves. Discovery is ongoing in this case.

	•	The Delaware Chancery Court cases: The first of these two cases was filed in 2002, and generally alleges the same claims pled in the consolidated shareholder class action described above, with the exception that there were no allegations related to the overstatement of natural gas and oil reserves. This lawsuit was voluntarily dismissed by plaintiffs in July 2005. The second Delaware derivative case was filed in April 2005 and seeks to recover the compensation paid to a former executive in 2001 alleging unjust enrichment allegedly attributable to round trip trading and restructuring of energy contracts and breach of fiduciary duty claims for failure to seek recovery of the 2001 compensation. In December 2005, the court dismissed this lawsuit because of the plaintiffs’ failure to make demand on the Board of Directors before filing suit.


	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. Formal discovery in this lawsuit is currently stayed.

	We and our representatives have insurance coverages that are applicable to each of these shareholder, derivative and ERISA lawsuits subject to certain deductibles and co-pay obligations. We have established certain accruals for these matters, which 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 Co. and Case Corporation. The suit alleges, among other things, that El Paso and Case violated ERISA and that they should be required to pay all amounts above the cap. Case further filed claims against El Paso asserting that El Paso is obligated to indemnify, defend and hold Case harmless for the amounts it would be required to pay. In separate rulings in 2004, the court ruled that pending a trial on the merits Case must pay the amounts incurred above the cap and that El Paso must

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reimburse Case for those payments. In January 2006, these rulings were upheld on appeal before a 3-member panel of the U.S. Court of Appeals for the 6th Circuit. In February 2006, we filed for a review of this decision by the full panel of the U.S. Court of Appeals for the 6th Circuit as a result of conflicting precedent. The appellate court has requested that the plaintiff file a reply brief in March 2006. If such a review is not granted, we will proceed with a trial on the merits with regard to the issue of whether the cap is enforceable. Until this is resolved, El Paso will indemnify Case for any payments Case makes above the cap, which are currently about $1.7 million per month. While we will continue to defend the action, based upon the ruling of the 6th Circuit and the lessening avenues of appellate reviews, we recorded a pre-tax charge of approximately $350 million for this matter during the fourth quarter of 2005. We have also filed for approval by the trial court various amendments to the medical benefit plans which would allow us to deliver the benefits to plan participants in a more cost effective manner. We will seek expeditious approval of such plan amendments. Although it is uncertain what plan amendments will ultimately be approved, the approval of plan amendments could reduce our overall costs and, as a result, could reduce our recorded liability.

Natural Gas Commodities Litigation. Beginning in August 2003, several lawsuits have been 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 information to industry trade publications that published gas indices. The first set of cases were filed in the United States District Court for the Southern District of New York which included: 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. The consolidated cases are styled, in re: Gas Commodity Litigation. In September 2004, El Paso Corporation was dismissed from the master case. In September 2005, the court certified the class to include all persons who purchased or sold NYMEX natural gas futures between January 1, 2000 and December 31, 2002. EPM and the remaining defendants have petitioned the United States Court of Appeals for the Second Circuit for permission to appeal the class certification order. The second set of cases involve similar allegations on behalf of commercial and residential customers. These cases were filed in the U.S. District Court for the Eastern District of California, which include Texas Ohio Energy, Inc. v. CenterPoint Energy, Inc. et al. (filed in November 2003), Fairhaven Power v. El Paso Corporation et al. (filed in September 2004), Utility Savings and Refund Services, et al. v. Reliant Energy, et al. (filed in December 2004) and Abelman Art Glass, et al. v. Encana Corporation, et al. (filed in December 2004). Each of these cases was transferred to a multi-district litigation proceeding (MDL), In re Western States Wholesale Natural Gas Antitrust Litigation, pending in the U.S. District Court for Nevada. These cases have been dismissed and have been appealed. The third set of cases also involve similar allegations on behalf of certain purchasers of natural gas. These include a purported class action lawsuit styled Leggett et al. v. Duke Energy Corporation et al. (filed in Chancery Court of Tennessee in January 2005), Ever-Bloom Inc. v. AEP Energy Services Inc. et al. (filed in June 2005), Farmland Industries, Inc. v. Oneok Inc. (filed in state court in Wyandotte County, Kansas in July 2005) and the purported class action Learjet, Inc. v. Oneok Inc. (filed in state court in Wyandotte County, Kansas in September 2005). All four actions have been transferred to the MDL proceeding in federal district court in Nevada. Similar motions to dismiss have either been filed or are anticipated to be filed in these cases as well. Our costs and legal exposure related to these lawsuits and claims are not currently determinable.

Grynberg. In 1997, a number of our subsidiaries were named defendants in actions 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 due to the alleged mismeasurement. The plaintiff seeks royalties along with interest, expenses, and punitive damages. The plaintiff also seeks injunctive relief with regard to future 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 were argued before a representative appointed by the court. In May 2005, the representative issued its recommendation, which if adopted by the district court judge, will result in the dismissal on jurisdictional

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grounds of six of the seven Qui Tam actions filed by Grynberg against El Paso subsidiaries. The seventh case involves only a few midstream entities owned by El Paso, which have meritorious defenses to the underlying claims. If the district court judge adopts the representative’s recommendations, an appeal by the plaintiff of the district court’s order is likely. 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 petition has since been filed as to the heating content claims. Motions for class certification have been briefed and argued in both proceedings, and the parties are awaiting the court’s ruling. Our costs and legal exposure related to these lawsuits and claims are not currently determinable.

Hurricane Litigation. One of our affiliates has been named in two class action petitions (subsequently consolidated by the court into one action) for damages filed in the United States District Court for the Eastern District of Louisiana against all natural gas and oil pipeline and exploration and production companies that dredged pipeline canals, installed transmission lines or drilled for natural gas and oil in the marshes of coastal Louisiana. The lawsuits, George Barasich, et al. v. Columbia Gulf Transmission Company, et al. and Charles Villa Jr., et al. v. Columbia Gulf Transmission Company, et al. assert that the defendants caused erosion and land loss which destroyed critical protection against hurricane surges and winds and was a substantial cause of the loss of life and destruction of property. The first lawsuit alleges damages associated with Hurricane Katrina. The second lawsuit alleges damages associated with Hurricanes Katrina and Rita. Our costs and legal exposures related to these lawsuits and claims are not currently determinable.

Bank of America. We are a named defendant, along with Burlington Resources, Inc. (Burlington), 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 consolidated class action has been settled pursuant to a settlement agreement executed in January 2006. 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. All the claims in this action have also been settled as part of the January 2006 settlement. The settlement of all these claims is subject to court approval, after a fairness hearing anticipated in the spring of 2006. We 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, Texas relating to indemnity issues between Burlington and us. That action was stayed by agreement of the parties and settled in November 2005, subject to the underlying class settlements being finalized and approved by the court. Upon final court approval of these settlements, our contribution will be approximately $30 million, which has been accrued as of December 31, 2005.

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, COPEL. 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. The final arbitration hearing was held in January 2006. A Curitiba court has ruled that the arbitration clause in the PPA is invalid. The project company is appealing this ruling.

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In February 2006, El Paso signed a letter of intent to settle this matter and to sell its interest in Araucaria to COPEL for $190 million. The sale is subject to negotiations of definitive purchase and sale agreements and requisite corporate approvals and its consummation would be subject to customary conditions to closing, including receipt of any necessary government approvals. The letter of intent provides that the parties will complete and sign definitive purchase and sale agreements by mid-April and that in the interim, the Araucaria arbitration will be suspended.

Our investment in the Araucaria project was $187 million at December 31, 2005. We have political risk insurance that covers a substantial portion of our investment in the project. Based on the future outcome of our dispute under the PPA and the letter of intent 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. The Macae project revenues are derived, in part, from minimum capacity and revenue payments made by Petrobras under a participation agreement that extends through August 2007. Petrobras filed a notice of arbitration that seeks rescission of the participation agreement and reimbursement of some or all of the capacity payments that it has made. An arbitration hearing took place in October 2005 and the arbitrators issued a partial final award on certain issues raised in the arbitration in November 2005. A final hearing is scheduled for late April 2006 on the remaining issues in the arbitration. We believe we have substantial defenses to the claims of Petrobras and continue to defend our legal rights vigorously. If, however, Petrobras’ claims were successful, they could result in a termination of the minimum revenue payments as well as Petrobras’ obligation to provide firm natural gas supply to the project through 2012.

On February 1, 2006, El Paso and Petrobras signed a memorandum of understanding that provides for the settlement of this matter and the sale of the entities that own El Paso’s interest in the Macae power plant. El Paso would sell these entities for a purchase price of approximately $358 million, adjusted for working capital, and approximately $225 million of project financing would be repaid from those sales proceeds. The sale is subject to negotiations of definitive purchase and sale agreements and requisite corporate approvals and its consummation would be subject to customary conditions to closing, including receipt of any necessary government approvals. We and Petrobras will attempt to complete the definitive agreements in March 2006 and in the interim, the arbitration proceedings will be suspended.

Based on the status of the arbitration proceedings and the indication of value we may ultimately receive for the settlement of this matter described in the memorandum of understanding, we recorded $333 million of impairment charges in 2005 on our investment in the Macae facility, which were included in discontinued operations. In addition, we did not recognize approximately $206 million of revenues under our participation agreement during 2005 and reserved $18 million of related receivables, which were included in discontinued operations, because of the uncertainty about their collectibility. Depending on the terms of the final agreement, we could be required to record additional losses related to the disposition and the resolution of disputes related to Macae.

Pending the issuance of the final arbitration award or the sale of Macae under the memorandum of understanding, Petrobras has been depositing the amounts owed directly into a restricted cash account, subject to Macae’s obligation to post a bank guarantee as security for any repayment obligation if Petrobras prevails in the dispute. We have recorded a liability of $186 million, included in liabilities related to discontinued operations, and the same amount in restricted cash related to these payments in addition to $1 million of debt service reserves held by Macae in their restricted cash accounts, included in assets from discontinued operations. We have reflected payments by Petrobras into this account as a non-cash investing transaction for purposes of our cash flow statement.

Petrobras’ non-payment has created an event of default under the applicable loan agreements. As a result, we have classified the debt as current. In light of the default of Petrobras under the participation agreement and the inability of Macae to continue to make ongoing payments under its loan agreements, one or more of the lenders could exercise 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 February 2006, Macae’s lenders issued notices of default due to the

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project’s non-payment of scheduled principal and interest payments and the lenders are reserving all of their rights under the loan agreements. In the event that the lenders foreclose on the project, we may incur additional losses of up to approximately $141 million. As new information becomes available or future material developments occur, we will reassess the carrying value of our interests in this project.

In late 2005, Macae also received an assessment from the Brazilian tax authorities totaling approximately $73 million, including $18 million for various import taxes and $55 million for interest and penalties related to the importation of equipment for the Macae plant during its construction. We believe we have valid defenses against the amounts assessed and have filed an appeal of the assessment to the administrative level of the Brazilian tax authorities and, accordingly, we have not accrued a liability related to this claim. In addition, we are pursuing a refund of tax payments that have been made related to interest income that the supreme court in Brazil, in a similar case, has recently determined to be unconstitutional. We have not accrued a receivable related to this potential tax receivable as collectibility is not assured. This tax claim, including interest that has accrued on these tax payments, totals approximately $21 million.

MTBE. In compliance with the 1990 amendments to the Clean Air Act, certain of our subsidiaries used the gasoline additive methyl tertiary-butyl ether (MTBE) in some of their gasoline. Certain subsidiaries have also produced, bought, sold and distributed MTBE. A number of lawsuits have been filed throughout the U.S. regarding MTBE’s potential impact on water supplies. Some of our subsidiaries are among the defendants in over 60 such lawsuits. As a result of a ruling issued in March 2004, these suits have been consolidated for pre-trial purposes in multi-district litigation in the U.S. District Court for the Southern District of New York. The plaintiffs, certain state attorneys general 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. Among other allegations, plaintiffs assert that gasoline containing MTBE is a defective product and that defendant refiners are liable in proportion to their market share. The plaintiff states of California and New Hampshire have filed an appeal to the 2nd Circuit Court of Appeals challenging the removal of the cases from state to federal court. That appeal is pending. In April 2005, the judge denied a motion by defendants to dismiss the lawsuits. In that opinion the Court recognized, for certain states, a potential commingled product market share basis for collective liability. Our costs and legal exposure related to these lawsuits are not currently determinable.

Government Investigations

Round Trip 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. On May 24, 2005, we received a subpoena from the SEC requesting the production of documents related to certain hedges on our natural gas production. We are cooperating with the SEC investigation.

Price Reporting. We have provided information to the Commodity Futures Trading Commission (CFTC) and the U.S. Attorney in response to their requests for information regarding price reporting of transactional data to the energy trade press. 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 will continue to cooperate with the SEC in its investigation related to such reserve revisions. Although we had also received federal grand jury subpoenas for documents with regard to these reserve revisions, in June 2005, we were informed that the U.S. Attorney’s office closed this investigation and will not pursue prosecution at this time.

Iraq Oil Sales. In September 2004, Coastal (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 related 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 and to produce certain documents in

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connection with The Coastal Corporation’s and El Paso’s participation in the Oil for Food Program. In June and December 2005, we received additional requests for documents and information from the SEC. We have also received informal requests for information and documents from several congressional committees related to Coastal’s purchases of Iraqi crude under the Oil for Food Program. In October 2005, a grand jury sitting in the Southern District of New York handed down an indictment against Oscar S. Wyatt, Jr., a former CEO and Chairman of Coastal. Also in October 2005, the Independent Inquiry Committee into the United Nations’ Oil for Food Program issued its final report. The report states that $201,877 in surcharges were paid with respect to a single contract entered into by our subsidiary, Coastal Petroleum NV (CPNV). The report lists Oscar Wyatt as the non-contractual beneficiary of the contract. The report indicates that the payments were made by two other individuals or entities and does not contend that CPNV paid that surcharge. We continue to cooperate with all government investigations into this matter.

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. We do not believe that these matters will have a material impact on us.

Rates and Regulatory Matters

EPNG Rate Case. In June 2005, EPNG filed a rate case with the FERC proposing an increase in revenues of 10.6 percent or $56 million over current tariff rates, new services and revisions to certain terms and conditions of existing services, including the adoption of a fuel tracking mechanism. Subject to refund, the rates became effective January 1, 2006. In addition, the reduced tariff rates provided to EPNG’s former full requirements customers under the terms of our FERC approved systemwide capacity allocation proceeding terminated. The FERC accepted a delay in the effective date of the proposed new services and certain other provisions until April 1, 2006. EPNG is continuing settlement discussions with its customers. The outcome of this rate case cannot be predicted with certainty at this time.

Other Contingencies

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

Navajo Nation. Nearly 900 looped pipeline miles of the north mainline of our EPNG pipeline system are located on lands held in trust by the United States for the benefit of the Navajo Nation. Our rights-of-way, on lands crossing the Navajo Nation expired in October 2005. Under an interim agreement reached in January 2006, the Navajo Nation consented to EPNG’s continued use and enjoyment of their existing rights-of-way through the end of 2006. Under the interim agreement, EPNG will make quarterly payments to the Navajo Nation, subject to a two-way adjustment if the parties reach final agreement on a long term right of way agreement prior to the end of 2006. Negotiations on the terms of the long-term agreement are continuing. Although the Navajo Nation has at times demanded more than ten times the $2 million annual fee that existed prior to the execution of the interim agreement, EPNG continues to offer a combination of cash and non-cash consideration, including collaborative projects to benefit the Navajo Nation. In addition, EPNG continues to preserve other legal and regulatory alternatives, which include continuing to pursue our application with the Department of the Interior for renewal of our rights-of-way on Navajo Nation lands. EPNG also continues to press for public policy intervention by Congress in this area. The Energy Policy Act of 2005 commissioned a comprehensive study of energy infrastructure rights-of-way on tribal lands. The study, to be conducted jointly by the Departments of Energy and the Department of Interior must be submitted to Congress by August 2006. It is uncertain whether our negotiation, public policy or litigation efforts will be

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successful, or if successful, what will be the ultimate cost of obtaining the rights-of-way or whether EPNG will be able to recover these costs in its rate case.

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 $1.3 billion as of December 31, 2005 (of which $0.7 billion relates to our Power segment, $0.2 billion relates to Macae which is included in assets and liabilities from discontinued operations and $0.4 billion relates to our Exploration and Production segment). In addition, we also have $225 million of project financing related to Macae which is non-recourse to us. For a further discussion, see Note 14. 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, the outcome of current disputes on the Macae power plant between us and Petrobras may negatively impact these investments and the impact could be material. See Note 3 a discussion of the resolution of these disputes.

We also own an investment in the Porto Velho power plant. The Porto Velho project is in the process of negotiating certain provisions of its power purchase agreements (PPA) 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 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 ongoing contract negotiations 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 approximately $302 million at December 31, 2005.

For each of our outstanding legal and other contingent matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. While the outcome of these matters, discussed above, cannot be predicted with certainty and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, we believe we have established appropriate reserves for these matters. However, it is possible that new information or future developments could require us to reassess our potential exposure related to these matters and adjust our accruals accordingly, and these adjustments could be material. As of December 31, 2005, we had approximately $574 million accrued, net of related insurance receivables, for outstanding legal and other contingent matters.

Environmental Matters

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. As of December 31, 2005, we had accrued approximately $379 million, which has not been reduced by $27 million for amounts paid directly under government sponsored programs. Our accrual includes approximately $368 million for expected remediation costs and associated onsite, offsite and groundwater technical studies, and approximately $11 million for related environmental legal costs. Of the $379 million accrual, $75 million was reserved for facilities we currently operate, and $304 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 $379 million to approximately $546 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 ($75 million). Second, where the most likely outcome cannot be estimated, a range of costs is established ($304 million to $471 million) and if no one amount in that range is more likely than any other, the lower end of the expected range has been accrued. Our environmental remediation projects are in various stages of completion. The liabilities we have recorded reflect our current estimates of amounts we will expend to remediate these sites. However, depending on the stage of completion or assessment, the ultimate extent of contamination or remediation required may not be known. As

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additional assessments occur or remediation efforts continue, we may incur additional liabilities. By type of site, our reserves are based on the following estimates of reasonably possible outcomes:


	December 31, 2005

Sites	Expected		High

	(In millions)
Operating	$	75	$	75
Non-operating		265		402
Superfund		39		69

Total	$	379	$	546

Below is a reconciliation of our accrued liability from January 1, 2005, to December 31, 2005 (in millions):


Balance as of January 1, 2005	$	380
Additions/adjustments for remediation activities		65
Payments for remediation activities		(66	)

Balance as of December 31, 2005	$	379

For 2006, we estimate that our total remediation expenditures will be approximately $76 million, most of which will be expended under government directed clean-up plans. In addition, we expect to make capital expenditures for environmental matters of approximately $91 million in the aggregate for the years 2006 through 2010. These expenditures primarily relate to compliance with clean air regulations.

Polychlorinated Biphenyls (PCB) Cost Recoveries. Pursuant to a consent order executed by TGP, our subsidiary, in May 1994, with the EPA, TGP has been conducting various remediation activities at certain of its compressor stations associated with the presence of PCBs, and certain other hazardous materials. 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 PCB 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 currently set to expire in June 2006. The agreement also provided for bi-annual audits of eligible costs. As of December 31, 2005, TGP had pre-collected PCB costs of approximately $132 million. The 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, 2005, TGP recorded a regulatory liability of $110 million for the 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 47 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, 2005, we have estimated our share of the remediation costs at these sites to be between $39 million and $69 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.

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It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. We may incur significant costs and liabilities in order to comply with existing environmental laws and regulations. It is also possible that other developments, such as increasingly strict environmental laws, regulations, and orders of regulatory agencies, as well as claims for damages to property and the environment or injuries to employees and other persons resulting from our current or past operations, could result in substantial costs and liabilities in the future. As this information becomes available, or other relevant developments occur, we will adjust our accrual amounts accordingly. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our reserves are adequate.

Commitments, Purchase Obligations and Other Matters

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 2006 until 2053. As of December 31, 2005, our total commitments under non-cancellable operating leases were approximately $217 million which have not been reduced by minimum sublease rentals of approximately $15 million due in the future under noncancelable subleases. Minimum annual rental commitments under our operating leases at December 31, 2005, were as follows:


Year Ending December 31,		Operating Leases

		(In millions)
2006		$	81
2007			71
2008			14
2009			11
2010			7
Thereafter			33

	Total	$	217

During 2004, we announced that we would consolidate our Houston-based operations into one location. We recorded a charge of $80 million in 2004 as a result of this decision and an additional charge of $27 million in 2005 upon vacating this remaining leased space and signing a termination agreement on the lease. Our remaining obligation under this terminated agreement is included in the table above. Rental expense on our non-terminated lease obligations for the years ended December 31, 2005, 2004, and 2003 was $55 million, $92 million, and $105 million.

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, but are not limited to, indemnification for income taxes, the resolution of existing disputes, environmental matters, and necessary expenditures to ensure the safety and integrity of the assets sold.

We record accruals for our guaranty and indemnification arrangements at their fair value when they are issued and subsequently adjust those accruals when we believe it is both probable that we will have to pay amounts under the arrangements and those amounts can be estimated. As of December 31, 2005, we had a liability of $91 million related to our guarantees and indemnification arrangements. These arrangements had a total stated value of $233 million, for which we are indemnified by third parties for $29 million. These amounts exclude guarantees for which we have issued related letters of credit discussed in Note 14.

In addition to the exposures described above, a trial court has ruled, which was upheld on appeal, that we are required to indemnify a third party for benefits being paid to a closed group of retirees of one of our former

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subsidiaries. We have a liability of approximately $380 million associated with our estimated exposure under this matter as of December 31, 2005. For a further discussion of this matter, see Retiree Medical Benefits Matters above.

Other Commercial Commitments. We have various other commercial commitments and purchase obligations that are not recorded on our balance sheet. At December 31, 2005, we had firm commitments under transportation and storage capacity contracts of $854 million, commodity purchase commitments of $142 million and other purchase and capital commitments (including maintenance, engineering, procurement and construction contracts) of $561 million.

We also hold cancelable easements or right-of-way arrangements from landowners permitting the use of land for the construction and operation of our pipeline systems. Currently, our obligation under these easements is not material to the results of our operations. However, we are currently negotiating a long-term right-of-way agreement with the Navajo Nation which could result in a significant commitment to us (see Other Contingencies).

17. Retirement Benefits

Overview of 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. We do not anticipate making any contributions to this pension plan in 2006.

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 several multi-employer pension plans for the benefit of our former employees who were union members. Our contributions to these plans during 2005, 2004 and 2003 were not material. We expect to contribute $5 million to the SERP and $11 million to the frozen plans in 2006.

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.

Retirement Savings Plan. We maintain a defined contribution plan covering all of our U.S. employees. We match 75 percent of participant basic contributions up to 6 percent of eligible compensation and can make additional discretionary matching contributions. Amounts expensed under this plan were approximately $30 million, $16 million and $14 million for the years ended December 31, 2005, 2004 and 2003.

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 $45 million to our postretirement plans in 2006. Medical benefits for these closed groups of retirees

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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.

Pension and Other Postretirement Benefits. 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

	2005		2004		2005		2004

	(In millions)
Projected benefit obligation	$	2,059	$	1,948	$	176	$	170
Accumulated benefit obligation		2,041		1,934		176		169
Fair value of plan assets		2,253		2,196		97		93
Accrued benefit liability		—		—		77		74
Prepaid benefit cost		918		960		—		—
Accumulated other comprehensive loss		—		—		75		70

We are required to recognize an additional minimum liability for pension plans with an accumulated benefit obligation in excess of plan assets. We recorded pre-tax other comprehensive income (loss) of $(5) million in 2005, $(33) million in 2004 and $18 million in 2003 related to the change in this additional minimum liability.

Change in Projected Benefit Obligation, Plan Assets and Funded Status. Our benefits are presented and computed as of and for the twelve months ended September 30.


								Other
								Postretirement
		Pension Benefits						Benefits

		2005			2004			2005			2004

		(In millions)
Change in benefit obligation:
	Projected benefit obligation at beginning of period	$	2,118		$	2,091		$	541		$	575
	Service cost		22			31			1			1
	Interest cost		121			121			29			34
	Participant contributions		—			—			34			27
	Settlements, curtailments and special termination benefits		—			(3	)		—			—
	Actuarial loss (gain)		178	⁽¹⁾		76	⁽¹⁾		(5	)		(20	)
	Benefits paid		(203	)		(198	)		(73	)		(76	)
	Other		(1	)		—			—			—

	Projected benefit obligation at end of period	$	2,235		$	2,118		$	527		$	541

Change in plan assets:
	Fair value of plan assets at beginning of period	$	2,289		$	2,197		$	220		$	196
	Actual return on plan assets		255			277			20			12
	Employer contributions		9			12			50			61
	Participant contributions		—			—			34			27
	Benefits paid		(203	)		(198	)		(73	)		(76	)
	Administrative expenses		—			1			—			—

	Fair value of plan assets at end of period	$	2,350		$	2,289		$	251		$	220

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								Other
								Postretirement
		Pension Benefits						Benefits

		2005			2004			2005			2004

		(In millions)
Reconciliation of funded status:
	Fair value of plan assets at September 30	$	2,350		$	2,289		$	251		$	220
	Less: Projected benefit obligation at end of period		2,235			2,118			527			541

	Funded status at September 30		115			171			(276	)		(321	)
	Fourth quarter contributions and income		2			2			11			13
	Unrecognized net actuarial loss⁽²⁾		814			800			20			32
	Unrecognized net transition obligation		—			—			—			8
	Unrecognized prior service cost		(13	)		(17	)		(5	)		(6	)

	Prepaid (accrued) benefit cost at December 31	$	918		$	956		$	(250	)	$	(274	)


⁽¹⁾	Increase is due primarily to changes in our discount rate and mortality assumptions in 2005 and 2004.

⁽²⁾	We recognize the difference between our actual return on plan assets and our expected return over a three year period. Our deferred actuarial gains and losses are recognized only to the extent that all of our remaining unrecognized actual gains and loses exceed the greater of 10 percent of our projected benefit obligations or market related value of plan assets.

The portion of our other postretirement benefit obligation included in current liabilities was $35 million and $38 million as of December 31, 2005 and 2004.

Expected Payment of Future Benefits. As of December 31, 2005, we expect the following payments under our plans:


Year Ending				Other Postretirement
December 31,		Pension Benefits		Benefits⁽¹⁾

		(In millions)
2006		$	167	$	49
2007			168		47
2008			167		46
2009			167		45
2010			166		44
2011-2015			815		197

	Total	$	1,650	$	428


⁽¹⁾	Includes a reduction of $3 million for the years 2006 through 2008 and $4 million for each year thereafter for an expected subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.

Components of Net Benefit Cost (Income). For each of the years ended December 31, the components of net benefit cost (income) are as follows:


											Other Postretirement
		Pension Benefits									Benefits

		2005			2004			2003			2005			2004			2003

		(In millions)
Service cost		$	22		$	31		$	36		$	1		$	1		$	1
Interest cost			121			121			134			29			34			35
Expected return on plan assets			(168	)		(187	)		(227	)		(12	)		(11	)		(9	)
Amortization of net actuarial loss			69			47			7			—			4			1
Amortization of transition obligation			—			—			(1	)		8			8			8
Amortization of prior service cost⁽¹⁾			(2	)		(3	)		(3	)		(1	)		(1	)		(1	)
Settlements, curtailment, and special termination benefits			—			(4	)		11			—			—			(6	)
Other			7			—			—			—			—			—

	Net benefit cost (income)	$	49		$	5		$	(43	)	$	25		$	35		$	29


⁽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.

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Actuarial Assumptions and Sensitivity Analysis. 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 2005, 2004 and 2003:


								Other
		Pension Benefits						Postretirement Benefits

		2005		2004		2003		2005		2004		2003

		(Percent)						(Percent)
Assumptions related to benefit obligations at September 30:
	Discount rate		5.50		5.75				5.25		5.75
	Rate of compensation increase		4.00		4.00
Assumptions related to benefit costs for the year ended December 31:
	Discount rate		5.75		6.00		6.75		5.75		6.00		6.75
	Expected return on plan assets⁽¹⁾		8.00		8.50		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.

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 10.9 percent, gradually decreasing to 5.0 percent by the year 2015. 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:


		2005			2004

		(In millions)
One percentage point increase:
	Aggregate of service cost and interest cost	$	1		$	1
	Accumulated postretirement benefit obligation		20			19
One percentage point decrease:
	Aggregate of service cost and interest cost	$	(1	)	$	(1	)
	Accumulated postretirement benefit obligation		(18	)		(18	)

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 2005		Actual 2004		Target		Actual 2005		Actual 2004

		(Percent)						(Percent)
Equity securities⁽¹⁾			60		65		62		65		61		60
Debt securities			40		34		37		35		32		33
Other			—		1		1		—		7		7

	Total		100		100		100		100		100		100


⁽¹⁾	During the third quarter of 2005, we liquidated all of the El Paso common stock included in plan assets. At September 30, 2004, actuals for our pension plans include $42 million (1.8 percent of total assets) of our common stock.

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

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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.

Other Matters. During the fourth quarter of 2005, we recorded an increase to our legal reserves of approximately $350 million associated with a closed group of retirees of the Case Corporation increasing our total liability to $380 million at December 31, 2005. A trial court ruled, which was upheld on appeal, that we are required to indemnify Case for benefits paid to these retirees. We estimated our liability under this ruling utilizing actuarial methods similar to those used in estimating our obligations associated with our other postretirement benefit plans; however, these legal reserves are not included in the disclosures related to our pension and other postretirement benefits above. For a further discussion of this matter, see Note 16.

18. Capital Stock

Common Stock

In 2003 and 2004, we issued 26.4 million shares to satisfy our obligations under the Western Energy Settlement. In December 2003, we completed a tender offer to exchange approximately 53 percent of our total 9.0% equity security units outstanding for $59 million in cash, and issued approximately 15.2 million shares of our common stock with a total market value of $119 million. In August 2005, we issued approximately 13.6 million shares of common stock to the remaining holders of $272 million of notes which originally formed a portion of our equity security units in settlement of their commitment to purchase the shares.

Convertible Perpetual Preferred Stock

In April 2005, we issued $750 million of convertible perpetual preferred stock. Cash dividends on the preferred stock are paid quarterly at the rate of 4.99% per annum if declared by our Board of Directors. Unpaid dividends accumulate at 4.99% until paid. Each share of the preferred stock is convertible at the holder’s option, at any time, subject to adjustment, into 76.7754 shares of our common stock under certain conditions. This conversion rate represents an equivalent conversion price of approximately $13.03 per share. The conversion rate is subject to adjustment based on certain events which include, but are not limited to, fundamental changes in our business such as mergers or business combinations as well as distributions of our common stock or adjustments to the current rate of dividends on our common stock. We will be able to cause the preferred stock to be converted into common stock after five years if our common stock is trading at a premium of 130 percent to the conversion price.

The net proceeds of $723 million from the issuance of the preferred stock, together with cash on hand, was used to prepay our Western Energy Settlement of approximately $442 million in April 2005, and to pay the redemption price (an aggregate of $300 million plus accrued dividends of $3 million) of the 6 million outstanding shares of 8.25% Series A cumulative preferred stock of our subsidiary, EPTP, in May 2005.

Dividends

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


				Convertible
		Common Stock		Preferred Stock
		($0.04/share)		(4.99%/year)

Amount paid in 2005			$104		$17
Amount paid in January 2006			$25		$10
Declared in 2006:
	Date of declaration		February 14, 2006		February 14, 2006
	Date payable		April 3, 2006		April 3, 2006
	Payable to shareholders on record		March 3, 2006		March 15, 2006

Dividends on our common stock are treated as reduction of additional paid-in-capital since we currently have an accumulated deficit. We expect dividends paid on our common and preferred stock in 2005 will be

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taxable to our stockholders because we anticipate that these dividends will be paid out of current or accumulated earnings and profits for tax purposes.

The terms of our 750,000 outstanding shares of 4.99% convertible preferred stock prohibit the payment of dividends on our common stock unless we have paid or set aside for payment all accumulated and unpaid dividends on such preferred stock for all preceding dividend periods. In addition, although our credit facilities do not contain any direct restriction on the payment of dividends, dividends are included as a fixed charge in the calculation of our fixed charge coverage ratio under our credit facilities. If our fixed charge ratio were to exceed the permitted maximum level, our ability to pay additional dividends would be restricted.

19. Stock-Based Compensation

We grant stock awards under various stock option plans. We account for our stock option plans using APB No. 25 and its related interpretations. Under our stock-based compensation plans, we may issue to our employees incentive stock options on our common stock (intended to qualify under Section 422 of the Internal Revenue Code), non-qualified stock options, restricted stock, restricted stock units, stock appreciation rights, performance shares, performance units and other stock-based awards. In addition, we may also issue shares under our employee stock purchase plan or issue deferred shares of common stock to our non-employee directors.

We are authorized to grant awards of approximately 42.5 million shares of our common stock under our current plans, which includes 35 million shares under our employee plan, 2.5 million shares under our non-employee director plan and 5 million shares under our employee stock purchase plan. At December 31, 2005, approximately 40 million shares remain available for grant under our current plans. In addition, we have approximately 28 million shares of stock option awards outstanding which were granted under terminated plans that obligate us to issue additional shares of common stock if they are exercised.

Non-qualified Stock Options

We granted non-qualified stock options to our employees in 2005, 2004 and 2003. 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

		2005					2004					2003

					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			33,923,578		$	42.73		36,245,014		$	47.90		43,208,374		$	49.16
	Granted		4,254,270		$	10.74		4,842,453		$	7.16		1,180,041		$	7.29
	Exercised		(219,244	)	$	7.31		(3,193	)	$	7.64		—			—
	Converted⁽¹⁾		—			—		(11,333	)	$	42.99		(871,250	)	$	42.00
	Forfeited or canceled		(9,875,119	)	$	45.78		(7,149,363	)	$	44.75		(7,272,151	)	$	49.53

Outstanding at end of year			28,083,485		$	37.12		33,923,578		$	42.73		36,245,014		$	47.90

Exercisable at end of year			20,792,538		$	46.96		28,455,056		$	49.45		28,703,151		$	46.04


⁽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.

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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, 2005.


	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 - $14.29		8,866,680		8.4	$	8.74		1,575,733	$	7.24
$14.30 - $28.59		2,292,259		1.3	$	21.76		2,292,259	$	21.76
$28.60 - $42.88		4,740,576		2.9	$	39.79		4,740,576	$	39.79
$42.89 - $57.18		4,405,272		3.6	$	46.91		4,405,272	$	46.91
$57.19 - $70.63		7,778,698		4.1	$	66.82		7,778,698	$	66.82

		28,083,485		5.0	$	37.12		20,792,538	$	46.96

SFAS No. 123 Assumptions

The fair value of each stock option granted was estimated on the date of grant using a separate Black-Scholes option-pricing calculation for each grant and was used to estimate the pro forma compensation expense in Note 1. Listed below is the weighted average of each assumption based on grants in each fiscal year:


Assumption:	2005		2004		2003

Expected Term in Years		4.82		5.35		6.19
Expected Volatility		42%		45%		52%
Expected Dividends		1.5%		2.1%		2.2%
Risk-Free Interest Rate		3.7%		3.7%		3.4%

These assumptions yielded a weighted average grant date fair value of options granted of $3.88 per share in 2005, $2.69 per share in 2004 and $3.21 per share in 2003.

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, which typically vest over three years from the date of grant. These shares carry voting and dividend rights, however, sale or transfer of the shares is restricted until they vest. We currently have outstanding and grant only time-based restricted share awards. Historically, we also granted performance-based restricted share awards; however, these shares have been fully vested or were forfeited prior to the end of 2005. The fair value of our time-based restricted shares is determined on the grant date, recorded as unamortized compensation as a component of stockholders’ equity on our balance sheet and amortized to compensation expense over the vesting period.

During 2005, 2004 and 2003 we granted 2.1 million, 3.1 million and 0.4 million shares of restricted stock awards with a weighted average grant date fair value of $10.78, $8.63 and $7.46 per share, respectively. We recognized compensation expense of $18 million, $23 million and $60 million during 2005, 2004 and 2003 related to the vesting of our restricted stock grants. At December 31, 2005, we had 4 million shares of time-based restricted stock outstanding and $17 million of unamortized compensation on our balance sheet that will be charged to compensation expense over the remaining vesting period.

Employee Stock Purchase Program

In July 2005, we reinstated our employee stock purchase plan under Section 423 of the Internal Revenue Code. The amended and restated plan allows participating employees the right to purchase our common stock on a quarterly basis at 95 percent of the market price on the last trading day of each month. At December 31, 2005, approximately 3 million shares remain available for issuance under this plan.

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20.	Business Segment Information

Our business consists of our Pipelines, Exploration and 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, a telecommunications business, and various other contracts and assets, all of which are immaterial. These other assets and contracts relate to assets or businesses sold including financial services, LNG and other items.

During 2005, we reclassified our south Louisiana gathering and processing assets, which were part of our Field Services segment, and the international power operations at our Nejapa, CEBU and East Asia Utilities power plants as discontinued operations. In March 2006, our Board of Directors approved the sale of our interest in the Macae power facility and we reclassified these operations as discontinued operations. Our operating results for all periods reflect each of these operations as discontinued.

Our Pipelines segment provides natural gas transmission, storage, and related services, primarily in the United States. 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 Exploration and Production segment is engaged in the exploration for and the acquisition, development and production of natural gas, oil and NGL, primarily in the United States and Brazil.

Our Marketing and Trading segment’s operations focus on marketing and managing the price risk associated with our natural gas and oil production as well as the management of our remaining trading portfolio.

Our Power segment primarily consists 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 manage the risks associated with our remaining assets in Brazil. As discussed above, our Power segment excludes Macae, which is reported as discontinued operations.

Our Field Services segment conducts midstream activities related to our remaining gathering and processing assets. We have disposed of substantially all of the assets in this segment. Our remaining assets were transferred to our Exploration and Production segment during the first quarter of 2006.

We had no customers whose revenues exceeded 10 percent of our total revenues in 2005, 2004 and 2003.

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

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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:


		2005			2004			2003

		(In millions)
Segment EBIT		$	1,281		$	863		$	1,480
Corporate and other			(521	)		(217	)		(852	)
Interest and debt expense			(1,354	)		(1,568	)		(1,768	)
Distributions on preferred interests of consolidated subsidiaries			(9	)		(25	)		(52	)
Income taxes			251			43			530

	Loss from continuing operations	$	(352	)	$	(904	)	$	(662	)

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


		As of or for the Year Ended December 31, 2005

		Segments

				Exploration and			Marketing						Field
		Pipelines		Production			and Trading			Power			Services		Corporate⁽¹⁾			Total

		(In millions)
Revenue from external customers
	Domestic	$	2,706	$	466	⁽²⁾	$	411		$	71		$	96	$	84		$	3,834
	Foreign		7		54	⁽²⁾		3			—			—		—			64
Intersegment revenue			70		1,267	⁽²⁾		(1,210	)		11			27		(93	)		72	⁽³⁾
Operation and maintenance			908		383			54			89			27		571			2,032
Depreciation, depletion, and amortization			437		612			4			2			3		42			1,100
(Gain) loss on long-lived assets			35		—			—			33			10		(4	)		74
Earnings (losses) from unconsolidated affiliates			161		19			—			(139	)		301		—			342
EBIT			1,226		696			(837	)		(89	)		285		(521	)		760
Discontinued operations, net of income taxes			—		9			—			(476	)		251		(34	)		(250	)
Assets of continuing operations ⁽⁴⁾
	Domestic		16,421		5,215			3,786			70			99		4,087			29,678
	Foreign⁽⁵⁾		26		355			33			1,106			—		57			1,577
Capital expenditures, capital investments and advances to unconsolidated affiliates, net ⁽⁶⁾			908		1,851			—			5			8		14			2,786
Total investments in unconsolidated affiliates			1,042		761			—			670			—		—			2,473


⁽¹⁾	Includes eliminations of intercompany transactions. Our intersegment revenues, along with our intersegment operating expenses, were incurred in the normal course of business between our operating segments. We recorded an intersegment revenue elimination of $91 million and an operation and maintenance expense elimination of $2 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 $583 million (see Note 3).
⁽⁵⁾	Of total foreign assets, approximately $324 million relates to property, plant and equipment and approximately $1.0 billion relates to investments in and advances to unconsolidated affiliates.
⁽⁶⁾	Amounts are net of third party reimbursements of our capital expenditures and returns of invested capital.

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		As of or for the Year Ended December 31, 2004

		Segments

					Exploration and			Marketing						Field
		Pipelines			Production			and Trading			Power			Services			Corporate⁽¹⁾			Total

		(In millions)
Revenue from external customers
	Domestic	$	2,554		$	535	⁽²⁾	$	697		$	241		$	938		$	132		$	5,097
	Foreign		9			26	⁽²⁾		2			67			—			15			119
Intersegment revenue			88			1,174	⁽²⁾		(1,207	)		94			159			(236	)		72	⁽³⁾
Operation and maintenance			777			365			53			240			74			201			1,710
Depreciation, depletion, and amortization			410			548			13			13			8			51			1,043
(Gain) loss on long-lived assets			(1	)		8			—			569			507			(6	)		1,077
Earnings (losses) from unconsolidated affiliates			173			4			—			(249	)		618			—			546
EBIT			1,331			734			(539	)		(747	)		84			(217	)		646
Discontinued operations, net of income taxes			—			(36	)		—			51			20			(78	)		(43	)
Assets of continuing operations ⁽⁴⁾
	Domestic		15,930			3,714			2,372			982			518			4,424			27,940
	Foreign⁽⁵⁾		58			366			32			1,572			—			96			2,124
Capital expenditures, capital investments and advances to unconsolidated affiliates, net⁽⁶⁾			1,047			728			—			26			(15	)		10			1,796
Total investments in unconsolidated affiliates			1,032			6			—			1,225			305			6			2,574


⁽¹⁾	Includes eliminations of intercompany transactions. Our intersegment revenues, along with our intersegment operating expenses, were incurred in the normal course of business between our operating segments. We recorded an intersegment revenue elimination of $236 million and an operation and maintenance expense elimination of $25 million, which is included in the “Corporate” column, to remove intersegment transactions.
⁽²⁾	Revenues from external customers include gains and losses related to our hedging of price risk associated with our natural gas and oil production. Intersegment revenues represent sales to our Marketing and Trading segment, which is responsible for marketing our production.
⁽³⁾	Relates to intercompany activities between our continuing operations and our discontinued operations.
⁽⁴⁾	Excludes assets of discontinued operations of $1,319 million (see Note 3).
⁽⁵⁾	Of total foreign assets, approximately $435 million relates to property, plant and equipment and approximately $1.5 billion relates to investments in and advances to unconsolidated affiliates.
⁽⁶⁾	Amounts are net of third party reimbursements of our capital expenditures and returns of invested capital.

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		As of or for the Year Ended December 31, 2003

		Segments

					Exploration and			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		$	907		$	113		$	5,693
	Foreign		2			—			—			213			2			13			230
Intersegment revenue			118			1,940	⁽²⁾		(2,065	)		145			374			(277	)		235	⁽³⁾
Operation and maintenance			847			342			158			445			85			95			1,972
Depreciation, depletion, and amortization			386			576			25			56			27			67			1,137
(Gain) loss on long-lived assets			(10	)		5			(3	)		185			173			510			860
Earnings (losses) from unconsolidated affiliates			119			13			—			(91	)		329			(7	)		363
EBIT			1,234			1,091			(809	)		(165	)		129			(852	)		628
Discontinued operations, net of income taxes			—			24			—			65			2			(1,303	)		(1,212	)
Assets of continuing operations ⁽⁴⁾
	Domestic		15,659			3,459			2,661			3,895			1,870			3,916			31,460
	Foreign⁽⁵⁾		27			308			5			1,967			—			141			2,448
Capital expenditures and investments in and advances to unconsolidated affiliates, net⁽⁶⁾			837			1,300			(1	)		1,083			(25	)		89			3,283
Total investments in unconsolidated affiliates			1,018			79			—			1,626			655			5			3,383


⁽¹⁾	Includes eliminations of intercompany transactions. Our intersegment revenues, along with our intersegment operating expenses, were incurred in the normal course of business between our operating segments. We recorded an intersegment revenue elimination of $338 million and an operation and maintenance expense elimination of $59 million, which is included in the “Corporate” column, to remove intersegment transactions.
⁽²⁾	Revenues from external customers include gains and losses related to our hedging of price risk associated with our natural gas and oil production. Intersegment revenues represent sales to our Marketing and Trading segment, which is responsible for marketing our production.
⁽³⁾	Relates to intercompany activities between our continuing operations and our discontinued operations.
⁽⁴⁾	Excludes assets of discontinued operations of $3.1 billion.
⁽⁵⁾	Of total foreign assets, approximately $486 million relates to property, plant and equipment, and approximately $1.7 billion relates to investments in and advances to unconsolidated affiliates.
⁽⁶⁾	Amounts are net of third party reimbursements of our capital expenditures and returns of invested capital. Our Power segment includes approximately $1 billion to acquire remaining interest in Chaparral and Gemstone (see Note 2).

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

We hold investments in unconsolidated affiliates which are accounted for using the equity method of accounting. Our income statement typically reflects (i) our share of net earnings directly attributable to these unconsolidated affiliates, and (ii) impairments and other adjustments recorded by us.

Our investment balance differs from the underlying net equity in our investments due primarily to purchase price adjustments or impairment charges recorded by us. As of December 31, 2005, our investment balance exceeded the net equity in the underlying net assets of these investments by $443 million due to these items. The largest of our purchase price adjustments is related to our investment in Four Star which we amortize over the life of its proved reserves. Our investment balance at December 31, 2004 was lower than the

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underlying net assets of our investments by $305 million. Our net ownership interest, investments in and earnings (losses) from our consolidated affiliates are as follows as of and for the years ended December 31:


			Net Ownership								Earnings (Losses) from
			Interest				Investment				Unconsolidated Affiliates

			2005		2004		2005		2004		2005			2004			2003

			(Percent)				(In millions)				(In millions)
Domestic:
	Four Star⁽¹⁾			43		—	$	754	$	—	$	19		$	—		$	—
	Citrus			50		50		596		589		66			65			43
	Enterprise Products Partners⁽²⁾			—		—		—		257		183			6			—
	GulfTerra Energy Partners⁽²⁾			—		—		—		—		—			601			419
	Midland Cogeneration Venture			44		44		—		191		(162	)		(171	)		29
	Great Lakes Gas Transmission			50		50		300		316		59			65			57
	Javelina⁽²⁾			—		40		—		45		121			15			(2	)
	Milford⁽²⁾			—		—		—		—		—			(1	)		(88	)
	Chaparral Investors⁽²⁾			—		—		—		—		—			—			(207	)
	Other Domestic Investments			various		various		55		47		19			25			(36	)

		Total domestic						1,705		1,445		305			605			215

Foreign:
	Korea Independent Energy Corporation⁽²⁾			—		50		—		176		127			22			29
	Araucaria Power⁽³⁾			60		60		187		186		—			—			—
	EGE Itabo⁽⁴⁾			25		25		24		88		(58	)		1			1
	Bolivia to Brazil Pipeline			8		8		96		86		20			24			17
	EGE Fortuna⁽⁴⁾			25		25		68		65		2			6			3
	Aguaytia Energy⁽⁴⁾			24		24		23		39		(11	)		(5	)		4
	San Fernando Pipeline			50		50		53		46		14			13			5
	Habibullah Power⁽⁴⁾⁽⁵⁾			50		50		16		20		(13	)		(46	)		(3	)
	Manaus⁽⁶⁾			100		—		65		—		10			—			—
	Rio Negro⁽⁶⁾			100		—		49		—		9			—			—
	Saba Power Company⁽⁴⁾			94		94		—		7		(7	)		(51	)		4
	Other Foreign Investments⁽⁵⁾			various		various		187		416		(56	)		(23	)		88

		Total foreign						768		1,129		37			(59	)		148

Total investments in unconsolidated affiliates							$	2,473	$	2,574

Total earnings from unconsolidated affiliates											$	342		$	546		$	363


⁽¹⁾	We acquired our interest in Four Star in 2005 in connection with our acquisition of Medicine Bow.

⁽²⁾	We sold our interest in Enterprise, Javelina and Korea Independent Energy Corporation in 2005 and GulfTerra in 2004. We also transferred our interest in Milford and consolidated Chaparral Investors during 2003.

⁽³⁾	We signed a letter of intent in February 2006 to sell our interest in this power facility.

⁽⁴⁾	We sold our interest in Aguaytia Energy in the first quarter of 2006. We have received approval from our Board of Directors to sell our interest in the other investments, which are targeted to close in the first half of 2006.

⁽⁵⁾	As of December 31, 2005 and 2004, we also had outstanding advances and receivables of $37 million and $64 million related to our investment in Habibullah Power. We also had other outstanding advances and receivables of $348 million and $320 million related to our other foreign investments as of December 31, 2005 and 2004, of which $331 million and $307 million are related to our investment in Porto Velho.

⁽⁶⁾	While we continue to have 100 percent ownership, we deconsolidated these investments in January 2005, upon entering into an agreement that will transfer ownership of these plants to the power purchaser in January 2008.

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Impairment charges and gains and losses on sales of equity investments are included in earnings from unconsolidated affiliates. During 2005, 2004 and 2003, our impairments, gains and losses were primarily a result of our decision to sell a number of these investments, but we also had several investments that experienced declines in their fair value due to changes in economics of the investments’ underlying contracts, or the markets they serve. These gains and losses consisted of the following:


Investment or Group	2005			2004			2003

	(In millions)
Midland Cogeneration Venture⁽¹⁾	$	(162	)	$	(161	)	$	—
Asia power investments		(64	)		(182	)		(1	)
Central and South American power investments		(89	)		—			24
Chaparral Investors		—			—			(207	)
Domestic power plants held for sale, sold or transferred		—			(44	)		(163	)
Dauphin Island Gathering/Mobile Bay Processing		—			—			(86	)
Enterprise/GulfTerra⁽²⁾		183			507			266
Javelina		111			—			—
KIECO		108			—			—
Other		4			4			(9	)

	$	91		$	124		$	(176	)


⁽¹⁾	Represents an impairment of our investment in 2004 and our proportionate share of losses from our investment in MCV in 2005, primarily based on MCV’s impairment of the plant assets.
⁽²⁾	See further discussion of these sales below.

Below is summarized financial information of our proportionate share of the operating results and financial position of our unconsolidated affiliates, including those in which we hold greater than a 50 percent interest.


		Year Ended December 31,

		2005			2004		2003

		(In millions)
Operating results data:
	Operating revenues	$	1,611		$	2,211	$	3,360
	Operating expenses		1,468			1,485		2,309
	Income (loss) from continuing operations		(123	)		388		519
	Net income (loss)⁽¹⁾		(123	)		388		520
Financial position data:⁽²⁾
	Current assets	$	1,002		$	1,248
	Non-current assets		4,016			5,265
	Short-term debt		250			250
	Other current liabilities		478			488
	Long-term debt		1,381			2,044
	Other non-current liabilities		786			779
	Minority interest		84			73
	Redeemable preferred stock		9			—
	Equity in net assets		2,030			2,879


⁽¹⁾	Includes net income of $15 million, $7 million and $119 million in 2005, 2004 and 2003, related to our proportionate share of affiliates in which we hold greater than a 50 percent interest.
⁽²⁾	Includes total assets of $485 million and $593 million as of December 31, 2005 and 2004 related to our proportionate share of affiliates in which we hold greater than a 50 percent interest.

We received distributions and dividends of $279 million and $358 million in 2005 and 2004, which includes less than $1 million and $23 million of returns of capital, from our investments.

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


	2005		2004		2003

	(In millions)
Operating revenue⁽¹⁾	$	117	$	199	$	216
Other revenue — management fees		—		3		13
Cost of sales		15		101		105
Reimbursement for operating expenses⁽¹⁾		5		95		139
Other income		9		8		10
Interest income		47		44		36
Interest expense		—		—		2


⁽¹⁾	Decrease in 2005 is due primarily to the sale of GulfTerra during 2004. See further discussion below.

GulfTerra and Enterprise

During 2003 and 2004, we owned a general partnership interest and common and preference units in GulfTerra Energy Partners, a limited partnership that held a variety of natural gas gathering, treating and processing assets. During 2004, GulfTerra merged with Enterprise Products Partners. Through a series of transactions in 2003, 2004 and 2005, we disposed of our interests in GulfTerra and Enterprise.

During 2003 and 2004, our Field Services segment managed GulfTerra’s daily operations and performed all of their administrative and operational activities through a series of agreements. We also had a number of other transactions with GulfTerra and Enterprise, including sales under natural gas transportation contracts and the sale of several of our natural gas gathering, treating and processing assets to GulfTerra in previous years. The following table summarizes the income statement impacts of our transactions with GulfTerra and Enterprise and the sale of our interests in those entities for the years ended December 31:


		2005		2004			2003

		(In millions)
Operating revenue		$	—	$	28		$	33
Operating expenses			—		113			114
Reimbursements			—		(71	)		(91	)
Earnings from unconsolidated affiliates
	Proportionate share of earnings and other income		—		100			153
	Gains on sales of investments		183		507			266

Matters that Could Impact Our Investments

Investments in Power Facilities. We have interests in a number of equity and cost basis investments that are considered variable interests under FIN No. 46(R). As of December 31, 2005, these entities consisted primarily of 17 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 4,240 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 investment in and advances to the entities ($564 million as of December 31, 2005) and our guarantees and other agreements associated with these entities (a maximum of $87 million as of December 31, 2005).

We own a 56 percent direct equity interest in a 261 MW power plant, Berkshire Power, located in Massachusetts. Berkshire’s lenders have asserted that Berkshire is in default on its loan agreement and on February 9, 2006, the lenders declared all obligations outstanding under the loan agreement to be immediately due and payable in full. This obligation is non-recourse to El Paso. We have previously fully impaired the value of this investment. However, we supply natural gas to Berkshire under a fuel management agreement. Berkshire had 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 which Berkshire reached in March 2005. We reserved the

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cumulative amount of the delayed payments based on Berkshire’s inability to generate adequate cash flows related to this agreement. We continue to supply fuel to the plant under the fuel supply agreement and we may incur losses if amounts owed on future fuel deliveries are not paid under this agreement because of Berkshire’s inability to generate adequate cash flow and the uncertainty surrounding their negotiations with their lenders. We are in discussions with the lenders and other owners of the project to transfer or terminate our interest in this project.

We supply gas to power plants that we partially own, including the Midland Cogeneration Venture (MCV) and Berkshire power projects. Due to their affiliated nature, we do not recognize mark-to-market gains or losses on these contracts to the extent of our ownership interest. However, should we sell our interests in these plants, we would record the cumulative unrecognized mark-to-market losses on these contracts, which totaled approximately $146 million as of December 31, 2005. We also have issued letters of credit and margin deposits to MCV for approximately $386 million and $44 million as of December 31, 2005, securing our obligation under the gas supply contracts.

Investment in Bolivia. We own an eight percent interest in the Bolivia to Brazil pipeline in which we have approximately $108 million of exposure, including guarantees, as of December 31, 2005. During 2005, political disputes in Bolivia related to pressure to nationalize the energy industry led to the resignation of the country’s president and the election of a new president. Recent changes in Bolivian law have also increased the combined rate of production taxes and royalties to 50 percent and required that existing exploration contracts be renegotiated. Actions by the new government in Bolivia could potentially lead to a disruption or cessation of the supply of gas from that country and impact the payments that our investment receives from Petrobras. We continue to monitor the political situation in Bolivia and as new information becomes available or future material developments arise, it is possible that a future impairment of our investment may occur.

Citrus Corporation. Citrus Trading Corporation (CTC), a subsidiary of Citrus Corp. (Citrus), in which we own a 50 percent equity interest, 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. CTC filed a motion for partial summary judgment, requesting that the court find that Duke failed to give proper notice of default to CTC regarding its alleged failure to maintain the letter of credit. Duke has filed an amended counter claim in federal court 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 has filed an answer to Duke’s motion. In August 2005, the federal district court issued an order denying both motions for summary judgment, asserting that the ambiguity in the contract and the performance of the parties created issues of fact that precluded summary judgment on either side. CTC has filed additional motions for partial summary judgment, requesting that the court find that Duke improperly asserted force majeure due to its alleged loss of gas supply and that Duke is in error in asserting that CTC breached contractual provisions that imposed resale restrictions and credit maintenance obligations. An unfavorable outcome on this matter could impact the value of our investment in Citrus. However, we do not expect the ultimate resolution of this matter to have a material adverse effect on us.

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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)
2005
	Operating revenues		$	1,088		$	1,169		$	752		$	961		$	3,970
	Loss on long-lived assets			7			—			3			64			74
	Operating income (loss)			242			390			(155	)		(298	)		179
	Earnings (losses) from unconsolidated affiliates			190			(19	)		14			157			342
	Income (loss) from continuing operations			113			67			(293	)		(239	)		(352	)
	Discontinued operations, net of income taxes⁽¹⁾			(7	)		(305	)		(19	)		81			(250	)
	Net income (loss)			106			(238	)		(312	)		(162	)		(606	)
	Net income (loss) available to common stockholders			106			(246	)		(321	)		(172	)		(633	)
	Basic and diluted earnings per common share
		Income (loss) from continuing operations		0.18			0.09			(0.47	)		(0.38	)		0.59
		Net income (loss)		0.17			(0.38	)		(0.50	)		(0.26	)		(0.98	)


			Quarters Ended

			March 31			June 30			September 30			December 31			Total

			(In millions, except per common share amounts)
2004
	Operating revenues		$	1,412		$	1,381		$	1,285		$	1,210		$	5,288
	Loss on long-lived assets			238			17			582			240			1,077
	Operating income (loss)			140			321			(409	)		(36	)		16
	Earnings (losses) from unconsolidated affiliates			87			98			617			(256	)		546
	Income (loss) from continuing operations			(143	)		(2	)		(179	)		(580	)		(904	)
	Discontinued operations, net of income taxes⁽¹⁾			(53	)		7			(35	)		38			(43	)
	Net income (loss)			(196	)		5			(214	)		(542	)		(947	)
	Basic and diluted earnings per common share
		Income (loss) from continuing operations		(0.22	)		0.00			(0.28	)		(0.91	)		(1.41	)
		Net income (loss)		(0.31	)		0.01			(0.33	)		(0.85	)		(1.48	)


⁽¹⁾	Our petroleum markets operations, our Canadian and certain other international natural gas and oil production operations, our south Louisiana gathering and processing operations, and our consolidated international power operations in Brazil, Central America and Asia are classified as discontinued operations (See Note 3 for further discussion).

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Supplemental Natural Gas and Oil Operations (Unaudited)

Our Exploration and Production segment is engaged in the exploration for, and the acquisition, development and production of natural gas, oil and NGL, primarily in the United States and Brazil.

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

2005
	Natural gas and oil properties:
		Costs subject to amortization	$	14,874	$	371	$	15,245
		Costs not subject to amortization		384		107		491

				15,258		478		15,736
	Less accumulated depreciation, depletion and amortization			11,021		183		11,204

	Net capitalized costs		$	4,237	$	295	$	4,532

	FAS 143 abandonment liability		$	186	$	4	$	190

2004
	Natural gas and oil properties:
		Costs subject to amortization	$	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

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

2005
	Property acquisition costs
		Proved properties		$	643	$	8	$	651
		Unproved properties			143		—		143
	Exploration costs				143		15		158
	Development costs				503		6		509

	Costs expended in 2005				1,432		29		1,461
	Asset retirement obligation costs				1		—		1

			Total costs incurred⁽¹⁾	$	1,433	$	29	$	1,462

	Unconsolidated investment in Four Star⁽¹⁾			$	769	$	—	$	769

2004
	Property acquisition costs
		Proved properties		$	33	$	69	$	102
		Unproved properties			32		3		35
	Exploration costs				185		25		210
	Development costs				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				467		95		562
	Development costs				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


⁽¹⁾	Includes $179 million of deferred income tax adjustments related to the acquisition of full-cost pool properties and $217 million related to the acquisition of our unconsolidated investment in Four Star.
⁽²⁾	Includes an increase to our property, plant and equipment of approximately $114 million in 2003 associated with our adoption of Statement of Financial Accounting Standard No. 143.

The table above includes capitalized internal costs incurred in connection with the acquisition, development and exploration of natural gas and oil reserves of $47 million, $44 million, and $58 million and capitalized interest of $30 million, $22 million and $19 million for the years ended December 31, 2005, 2004 and 2003.

In our January 1, 2006 reserve report, the amounts estimated to be spent in 2006, 2007 and 2008 to develop our worldwide proved undeveloped reserves are $318 million, $459 million and $221 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, 2005, pending determination of proved reserves (in millions):


		Cumulative		Costs Excluded						Cumulative
		Balance		for Years Ended						Balance
				December 31
		December 31,								December 31,
		2005		2005		2004		2003		2002

Worldwide⁽¹⁾⁽²⁾
	Acquisition	$	358	$	221	$	52	$	26	$	59
	Exploration		132		29		13		29		61
	Development		1		—		—		—		1

		$	491	$	250	$	65	$	55	$	121


⁽¹⁾	Includes operations in the United States and Brazil.
⁽²⁾	Includes capitalized interest of $19 million, $7 million, and less than $1 million for the years ended December 31, 2005, 2004, and 2003.

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 2006 through 2008. Our total amortization expense per Mcfe for the United States was $2.25, $1.84, and $1.40 in 2005, 2004, and 2003 and $2.33 and $2.02 for Brazil in 2005 and 2004. We had no production in Brazil during 2003. Included in our worldwide depreciation, depletion and amortization expense is accretion expense of $0.10/Mcfe, $0.08/Mcfe and $0.06/Mcfe for 2005, 2004 and 2003 for the United States and $0.01/Mcfe for Brazil in 2005 and 2004, 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, 2005 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 92 percent of our properties. Based on the amount of proved reserves determined by Ryder Scott, we believe these reported reserve amounts are

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reasonable. 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 tables below exclude our Power segment’s equity interest in in proved reserves in Indonesia and Peru. Our Power segment has completed or expects to complete these sales in 2006. Combined proved reserve balances for these interests were 162,254 MMcf of natural gas and 2,058 MBbls of oil, condensate and NGL for total natural gas equivalents of 174,600 MMcfe, all net to our ownership interests.


												Oil and Condensate									NGL
			Natural Gas (in Bcf)									(in MBbls)									(in MBbls)

			United									United									United
			States⁽¹⁾			Brazil			Worldwide			States⁽¹⁾			Brazil			Worldwide			States⁽¹⁾⁽³⁾

Consolidated
Net proved developed and undeveloped reserves
	January 1, 2003			2,488			—			2,488			38,354			—			38,354			21,607
		Revisions of previous estimates		(24	)		—			(24	)		895			—			895			(2,717	)
		Extensions, discoveries and other		405			—			405			5,000			20,543			25,543			1,795
		Purchases of reserves in place		2			—			2			5			—			5			27
		Sales of reserves in place		(471	)		—			(471	)		(4,328	)		—			(4,328	)		(504	)
		Production		(339	)		—			(339	)		(7,555	)		—			(7,555	)		(4,223	)

	December 31, 2003			2,061			—			2,061			32,371			20,543			52,914			15,985
		Revisions of previous estimates		(172	)		—			(172	)		(999	)		252			(747	)		724
		Extensions, discoveries and other		79			38			117			2,214			1,848			4,062			58
		Purchases of reserves in place		15			38			53			—			1,848			1,848			—
		Sales of reserves in place		(21	)		—			(21	)		(1,276	)		—			(1,276	)		(47	)
		Production		(238	)		(7	)		(245	)		(4,979	)		(320	)		(5,299	)		(3,519	)

	December 31, 2004			1,724			69			1,793			27,331			24,171			51,502			13,201
		Revisions of previous estimates		(43	)		(2	)		(45	)		260			7,927			8,187			1,148
		Extensions, discoveries and other		183			5			188			8,145			772			8,917			169
		Purchases of reserves in place		192			—			192			13,338			—			13,338			772
		Sales of reserves in place		(18	)		—			(18	)		(969	)		—			(969	)		(89	)
		Production		(207	)		(16	)		(223	)		(4,877	)		(620	)		(5,497	)		(2,639	)

	December 31, 2005			1,831			56			1,887			43,228			32,250			75,478			12,562

Proved developed reserves
	December 31, 2003			1,428			—			1,428			22,821			—			22,821			14,088
	December 31, 2004			1,287			54			1,341			19,641			2,613			22,254			11,943
	December 31, 2005			1,404			27			1,431			28,581			1,144			29,725			11,010
Unconsolidated investment in Four Star ⁽²⁾
	December 31, 2005
	Net proved developed and undeveloped reserves			193			—			193			3,349			—			3,349			6,668
	Proved developed reserves			158			—			158			3,266			—			3,266			5,399


⁽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⁾	Our unconsolidated share of Four Star’s proved reserves has been estimated based on an evaluation of those reserves by El Paso’s internal reservoir engineers, and not by engineers of Four Star. An independent reservoir engineering firm, Ryder Scott, which was engaged by us, prepared an estimate on 86 percent of Four Star’s proved reserves. Based on the amount of Four Star’s proved reserves determined by Ryder Scott, we believe our reported reserve amounts are reasonable.
⁽³⁾	All of our NGL reserves are in the United States.

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. 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, 2005.

We maintain an agreement with a subsidiary of Nabors Industries in which we sold interests in 23 wells. As the wells were developed, Nabors paid 20 percent of the drilling and development costs in exchange for 20 percent of the net profits of the wells sold. As each well commenced, Nabors received an overriding royalty interest in the form of a net profits interest in the well, under which they are entitled to receive 20 percent of the aggregate net profits of all wells until they recover 117.5 percent of their aggregate investment. Upon recovery, the net profits interest converts to a proportionately reduced 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 Nabors’ costs.

Results of operations from producing activities by fiscal year were as follows at December 31 (in millions):


				United
				States			Brazil			Worldwide

2005
	Net Revenues
		Sales to external customers		$	431		$	62		$	493
		Affiliated sales			1,256			(9	)		1,247

			Total		1,687			53			1,740
	Production costs⁽¹⁾				(253	)		(8	)		(261	)
	Depreciation, depletion and amortization				(567	)		(45	)		(612	)

					867			—			867
	Income tax expense				(309	)		—			(309	)

	Results of operations from producing activities			$	558		$	—		$	558

	Equity earnings from unconsolidated investment in Four Star			$	19		$	—		$	19

2004
	Net Revenues
		Sales to external customers		$	500		$	26		$	526
		Affiliated sales			1,155			—			1,155

			Total		1,655			26			1,681
	Production costs⁽¹⁾				(210	)		—			(210	)
	Depreciation, depletion and amortization				(530	)		(18	)		(548	)

					915			8			923
	Income tax expense				(333	)		(3	)		(336	)

	Results of operations from producing activities			$	582		$	5		$	587

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				United
				States			Brazil			Worldwide

2003
	Net Revenues
		Sales to external customers		$	147		$	—		$	147
		Affiliated sales			1,912			—			1,912

			Total		2,059			—			2,059
	Production costs⁽¹⁾				(229	)		—			(229	)
	Depreciation, depletion and amortization				(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


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

The standardized measure of discounted future net cash flows relating to our consolidated proved natural gas and oil reserves at December 31 is as follows (in millions):


	United
	States			Brazil			Worldwide

2005
Future cash inflows⁽¹⁾	$	18,175		$	1,992		$	20,167
Future production costs		(3,968	)		(453	)		(4,421	)
Future development costs		(1,335	)		(309	)		(1,644	)
Future income tax expenses		(3,160	)		(286	)		(3,446	)

Future net cash flows		9,712			944			10,656
10% annual discount for estimated timing of cash flows		(3,660	)		(381	)		(4,041	)

Standardized measure of discounted future net cash flows	$	6,052		$	563		$	6,615

Standardized measure of discounted future net cash flows, including effects of hedging activities	$	5,748		$	560		$	6,308

Unconsolidated investment in Four Star
Standardized measure of discounted future net cash flows	$	617		$	—		$	617

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

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⁽¹⁾	United States excludes $502 million, $1 million and $104 million of future net cash outflows attributable to hedging activities in the years 2005, 2004 and 2003. Brazil excludes $4 million and $5 million of future net cash outflows attributable to hedging activities in 2005 and 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 $10.08 per MMBtu for natural gas and $61.04 per barrel of oil at December 31, 2005. In the United States, after adjustments for transportation and other charges, net prices were $8.33 per Mcf of gas, $57.42 per barrel of oil and $36.61 per barrel of NGL at December 31, 2005. 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.

The following are the principal sources of change in our consolidated worldwide standardized measure of discounted future net cash flows (in millions):


	Years Ended December 31,⁽¹⁾

	2005			2004			2003

	(In millions)
Sales and transfers of natural gas and oil produced net of production costs	$	(1,477	)	$	(1,470	)	$	(1,829	)
Net changes in prices and production costs		2,884			29			1,586
Extensions, discoveries and improved recovery, less related costs		793			268			1,105
Changes in estimated future development costs		2			4			(16	)
Previously estimated development costs incurred during the period		247			156			220
Revision of previous quantity estimates		47			(453	)		(94	)
Accretion of discount		476			568			526
Net change in income taxes		(1,093	)		257			159
Purchases of reserves in place		956			114			5
Sale of reserves in place		(83	)		(75	)		(1,229	)
Change in production rates, timing and other		(333	)		(94	)		150

Net change	$	2,419		$	(696	)	$	583

⁽¹⁾ This disclosure reflects changes in the standardized measure calculation excluding the effects of hedging activities.

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SCHEDULE II

EL PASO CORPORATION

VALUATION AND QUALIFYING ACCOUNTS

Years Ended December 31, 2005, 2004 and 2003

(In millions)


				Charged
		Balance at		to Costs						Charged			Balance
		Beginning		and						to Other			at End
Description		of Period		Expenses			Deductions			Accounts			of Period

2005
	Allowance for doubtful accounts	$	198	$	(68	)	$	(54	)⁽¹⁾	$	(9	)	$	67
	Valuation allowance on deferred tax assets		51		40	⁽²⁾		(5	)		21			107
	Legal reserves		592		496			(516	) ⁽³⁾⁽⁴⁾		2			574
	Environmental reserves		380		65			(66	)⁽⁴⁾		—			379
2004
	Allowance for doubtful accounts	$	272	$	(48	)	$	(22	)⁽¹⁾	$	(4	)	$	198
	Valuation allowance on deferred tax assets		9		46	⁽²⁾		(4	)		—			51
	Legal reserves		1,169		145			(655	) ⁽³⁾⁽⁴⁾		(67	)		592
	Environmental reserves		412		17			(51	)⁽⁴⁾		2			380
2003
	Allowance for doubtful accounts	$	176	$	18		$	(31	)⁽¹⁾	$	109	⁽⁵⁾	$	272
	Valuation allowance on deferred tax assets		72		4			(68	)⁽²⁾		1			9
	Legal reserves		1,031		180	⁽³⁾		(43	)⁽⁴⁾		1			1,169
	Environmental reserves		389		8			(52	)⁽⁴⁾		67	⁽⁶⁾		412


⁽¹⁾	Relates primarily to accounts written off.
⁽²⁾	Relates primarily to valuation allowances for deferred tax assets related to the Western Energy Settlement, foreign ceiling test charges, foreign asset impairments and state and foreign net operating loss carryovers.
⁽³⁾	Relates to our Western Energy Settlement of $104 million in 2003. In 2005 and 2004, we paid approximately $442 million and $602 million to the settling parties.
⁽⁴⁾	Relates primarily to payments for various litigation reserves, including the Western Energy Settlement, environmental remediation reserves or revenue crediting and rate settlement reserves.
⁽⁵⁾	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.
⁽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 9.01, Financial Statements and Exhibits.


Exhibit
No.			DESCRIPTION

	12		Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends
	23	.A	Consent of Independent Registered Public Accounting Firm, PricewaterhouseCoopers LLP (Houston)
	23	.C	Consent of Ryder Scott Company, L.P.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	EL PASO CORPORATION

	By: /s/John R. Sult

	John R. Sult
	Senior Vice President and Controller
	(Principal Accounting Officer)

Dated: May 12, 2006

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