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El Paso Corp/DE · 10-K · For 12/31/05

Filed On 3/7/06 5:29pm ET · SEC File 1-14365 · Accession Number 950129-6-2345

  As Of               Filer                 Filing     As/For/On Docs:Pgs              Issuer               Agent

 3/07/06  El Paso Corp/DE                   10-K       12/31/05   16:959                                    Bowne of Houston...01/FA

Annual Report · Form 10-K
Filing Table of Contents

Document/Exhibit                   Description                      Pages   Size 

 1: 10-K        El Paso Corporation - December 31, 2005             HTML  3,571K 
 2: EX-10.I.1   Amendment #4 to Supplemental Benefits Plan          HTML     18K 
 3: EX-10.S.1   Supplement #2 to Severance Pay Plan                 HTML     25K 
 4: EX-10.Y     Form of Indemnification Agreement                   HTML     62K 
 5: EX-10.HH.1  Amendment #1 to 2005 Omnibus Incentive              HTML     24K 
                          Compensation Plan                                      
 6: EX-10.KK    2005 Supplemental Benefits Plan                     HTML    100K 
 7: EX-12       Ratio of Earnings to Combined Fixed Charges and     HTML     51K 
                          Preferred Stock Dividends                              
 8: EX-21       Subsidiaries of El Paso Corporation                 HTML    637K 
 9: EX-23.A     Consent of Independent Registered Public            HTML     12K 
                          Accounting Firm, Pricewaterhousecoopers                
                          Llp                                                    
10: EX-23.B     Consent of Independent Registered Public            HTML     13K 
                          Accounting Firm, Pricewaterhousecoopers                
                          Llp                                                    
11: EX-23.C     Consent of Ryder Scott Company, L.P.                HTML     15K 
12: EX-31.A     Certification of Ceo Pursuant to Section 302        HTML     17K 
13: EX-31.B     Certification of Cfo Pursuant to Section 302        HTML     17K 
14: EX-32.A     Certification of Ceo Pursuant to Section 906        HTML     13K 
15: EX-32.B     Certification of Cfo Pursuant to Section 906        HTML     13K 
16: 10-K        El Paso Corporation - December 31, 2005              PDF  2,336K

10-K · El Paso Corporation - December 31, 2005
Document Table of Contents

Page	(sequential)	\|	(alphabetic)	Top
			Alternative Formats (RTF, XML, et al.) Business Certain Relationships and Related Transactions Changes in and Disagreements with Accountants on Accounting and Financial Disclosure Controls and Procedures Directors and Executive Officers of the Registrant Executive Compensation Exhibits and Financial Statement Schedules Financial Statements and Supplementary Data Item 1 Item 10 Item 11 Item 12 Item 13 Item 14 Item 15 Item 1A Item 1B Item 2 Item 3 Item 4 Item 5 Item 6 Item 7 Item 7A Item 8 Item 9 Item 9A Item 9B Legal Proceedings Management s Discussion and Analysis of Financial Condition and Results of Operations Market for Registrant s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Other Information Part I Part Ii Part Iii Part Iv Principal Accountant Fees and Services Properties Quantitative and Qualitative Disclosures About Market Risk Risk Factors Safe Harbor Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters Selected Financial Data Signatures Submission of Matters to a Vote of Security Holders Table of Contents Unresolved Staff Comments
1	1st Page
"	Table of Contents
"	Part I
"	Item 1
"	Business
"	Item 1A
"	Risk Factors
"	Safe Harbor
"	Item 1B
"	Unresolved Staff Comments
"	Item 2
"	Properties
"	Item 3
"	Legal Proceedings
"	Item 4
"	Submission of Matters to a Vote of Security Holders
"	Part Ii
"	Item 5
"	Market for Registrant s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
"	Item 6
"	Selected Financial Data
"	Item 7
"	Management s Discussion and Analysis of Financial Condition and Results of Operations
"	Item 7A
"	Quantitative and Qualitative Disclosures About Market Risk
"	Item 8
"	Financial Statements and Supplementary Data
"	Item 9
"	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
"	Item 9A
"	Controls and Procedures
"	Item 9B
"	Other Information
"	Part Iii
"	Item 10
"	Directors and Executive Officers of the Registrant
"	Item 11
"	Executive Compensation
"	Item 12
"	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
"	Item 13
"	Certain Relationships and Related Transactions
"	Item 14
"	Principal Accountant Fees and Services
"	Part Iv
"	Item 15
"	Exhibits and Financial Statement Schedules
"	Signatures

This is an EDGAR HTML document rendered as filed. [ Alternative Formats ]

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

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

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2005

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

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to .

Commission File Number 1-14365

El Paso Corporation

(Exact Name of Registrant as Specified in Its Charter)


Delaware		76-0568816
(State or Other Jurisdiction of		(I.R.S. Employer
Incorporation or Organization)		Identification No.)

El Paso Building 1001 Louisiana Street Houston, Texas (Address of Principal Executive Offices)		77002 (Zip Code)

Telephone Number: (713) 420-2600

Internet Website: www.elpaso.com

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


		Name of Each Exchange
Title of Each Class		on which Registered

Common Stock, par value $3 per share		New York Stock Exchange

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o.

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ.

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ.

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

Aggregate market value of the voting stock (which consists solely of shares of common stock) held by non-affiliates of the registrant as of June 30, 2005 computed by reference to the closing sale price of the registrant’s common stock on the New York Stock Exchange on such date: $7,594,102,633.

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

Common Stock, par value $3 per share. Shares outstanding on February 24, 2006: 659,210,298

Documents Incorporated by Reference

List hereunder the following documents if incorporated by reference and the part of the Form 10-K (e.g., Part I, Part II, etc.) into which the document is incorporated: Portions of our definitive proxy statement for the 2006 Annual Meeting of Stockholders are incorporated by reference into Part III of this report. These will be filed no later than April 30, 2006.

EL PASO CORPORATION

TABLE OF CONTENTS


	Caption	Page

	PART I
Item 1.	Business		1
Item 1A.	Risk Factors		24
	Cautionary Statement for Purposes of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995
Item 1B.	Unresolved Staff Comments		33
Item 2.	Properties		33
Item 3.	Legal Proceedings		33
Item 4.	Submission of Matters to a Vote of Security Holders		35
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		36
Item 6.	Selected Financial Data		37
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		38
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		79
Item 8.	Financial Statements and Supplementary Data		82
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		155
Item 9A.	Controls and Procedures		155
Item 9B.	Other Information		155
	PART III
Item 10.	Directors and Executive Officers of the Registrant		156
Item 11.	Executive Compensation		156
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		156
Item 13.	Certain Relationships and Related Transactions		156
Item 14.	Principal Accountant Fees and Services		156
	PART IV
Item 15.	Exhibits and Financial Statement Schedules		157
	Signatures		187
Amendment #4 to Supplemental Benefits Plan
Supplement #2 to Severance Pay Plan
Form of Indemnification Agreement
Amendment #1 to 2005 Omnibus Incentive Compensation Plan
2005 Supplemental Benefits Plan
Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends
Subsidiaries of El Paso Corporation
Consent of Independent Registered Public Accounting Firm, PricewaterhouseCoopers LLP
Consent of Independent Registered Public Accounting Firm, PricewaterhouseCoopers LLP
Consent of Ryder Scott Company, L.P.
Certification of CEO pursuant to Section 302
Certification of CFO pursuant to Section 302
Certification of CEO pursuant to Section 906
Certification of CFO pursuant to Section 906

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


/d		= per day
Bbl		= 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.

PART I

ITEM 1. 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 Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations. For our segment operating results and assets, see Part II, Item 8, Financial Statements and Supplementary Data, Note 20, which is incorporated herein by reference. 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 Part II, Item 8, 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 Part II, Item 7 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. As of December 31, 2005, we owned or had interests in 23 power facilities in 11 countries with a total generating capacity of approximately 6,334 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

Macae⁽²⁾

Brazil

100

928

Petrobras

2007

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⁾	Our Macae project in Brazil is consolidated. All others in this table are reflected as investments in unconsolidated affiliates in our financial statements.
⁽²⁾	See Part II, Item 8, Financial Statements and Supplementary Data, Note 16 for a further discussion of these plants.
⁽³⁾	See Part II, Item 8, 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 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 Part II, Item 8, Financial Statements and Supplementary Data, Note 16, and is incorporated herein by reference.

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.

ITEM 1A. RISK FACTORS


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

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

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

Risks Related to Our Business


	*Our operations are subject to operational hazards and uninsured risks.*

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

While we maintain insurance against many of these risks to the extent and in amounts that we believe are reasonable, this insurance does not cover all risks. Many of our insurance coverages have material deductibles and self-insurance levels, as well as limits on our maximum recovery. As a result, our financial condition and operations could be adversely affected if a significant event occurs that is not fully covered by insurance.


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

Most of the natural gas and NGL we transport and store are owned by third parties. As a result, the volume of natural gas and NGL involved in these activities depends on the actions of those third parties and is beyond our control. Further, the following factors, most of which are beyond our control, may unfavorably

impact our ability to maintain or increase current throughput, to renegotiate existing contracts as they expire or to remarket unsubscribed capacity on our pipeline systems:


	•	service area competition;

	•	expiration and/or turn back of significant contracts;

	•	changes in regulation and action of regulatory bodies;

	•	future weather conditions;

	•	price competition;

	•	drilling activity and availability of natural gas supplies;

	•	decreased availability of conventional gas supply sources and the availability and timing of other gas supply sources, such as LNG;

	•	decreased natural gas demand due to various factors, including increases in prices and the increased availability or popularity of alternative energy sources such as hydroelectric power;

	•	increased costs of capital;

	•	opposition to energy infrastructure development, especially in environmentally sensitive areas;

	•	adverse general economic conditions;

	•	expiration and/or renewal of existing interests in real property, including real property on Native American lands; and

	•	unfavorable movements in natural gas and NGL prices in certain supply and demand areas.


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

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

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


	•	competition by other pipelines, including the change in rates or upstream supply of existing pipeline competitors, as well as the proposed construction by other companies of additional pipeline capacity or LNG terminals in markets served by our interstate pipelines;

	•	changes in state regulation of local distribution companies, which may cause them to negotiate short-term contracts or turn back their capacity when their contracts expire;

	•	reduced demand and market conditions in the areas we serve;

	•	the availability of alternative energy sources or gas supply points; and

	•	regulatory actions.

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


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

Revenues generated by our transmission, storage and LNG contracts depend on volumes and rates, both of which can be affected by the prices of natural gas, LNG and NGL. Increased prices could result in a reduction of the volumes transported by our customers, such as power companies who, depending on the price

of fuel, may not dispatch gas-fired power plants. Increased prices could also result in industrial plant shutdowns or load losses to competitive fuels as well as local distribution companies’ loss of customer base. The success of our transmission, storage and LNG operations is subject to continued development of additional oil and natural gas reserves and our ability to access additional supplies from interconnecting pipelines or LNG facilities to offset the natural decline from existing wells connected to our systems. A decline in energy prices could cause a decrease in these development activities and could cause a decrease in the volume of reserves available for transmission, storage and processing through our systems. Pricing volatility may, in some cases, impact the value of under or over recoveries of retained gas, imbalances and system encroachments. If natural gas prices in the supply basins connected to our pipeline systems are higher than prices in other natural gas producing regions, our ability to compete with other transporters may be negatively impacted. Furthermore, fluctuations in pricing between supply sources and market areas could negatively impact our transportation revenues. Fluctuations in energy prices are caused by a number of factors, including:


	•	regional, domestic and international supply and demand;

	•	availability and adequacy of transportation facilities;

	•	energy legislation;

	•	federal and state taxes, if any, on the sale or transportation of natural gas and NGL;

	•	abundance of supplies of alternative energy sources; and

	•	political unrest among oil producing countries.


	*The expansion of our pipeline systems by constructing new facilities subjects us to construction and other risks that may adversely affect the financial results of our pipeline businesses.*

We may expand the capacity of our existing pipeline, storage or LNG facilities by constructing additional facilities. Construction of these facilities is subject to various regulatory, development and operational risks, including:


	•	the ability to obtain all necessary approvals and permits by regulatory agencies on a timely basis on terms that are acceptable to us;

	•	potential changes of federal, state and local statutes and regulations, including environmental requirements that prevent a project from proceeding or increase the anticipated cost of the expansion project;

	•	impediments on our ability to acquire rights-of-ways or land rights on a timely basis or within our anticipated costs;

	•	the ability to construct projects within anticipated costs, including the risk that we may incur cost overruns resulting from inflation or increased costs of equipment, materials, labor, or other factors beyond our control, that may be material;

	•	anticipated future growth in natural gas supply does not materialize; and

	•	the lack of transportation, storage or throughput commitments that result in write-offs of development costs.

Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated costs. As a result, new facilities may not achieve our expected investment return, which could adversely affect our financial position or results of operations.


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

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


	•	the level of consumer demand for, and the supply of, natural gas and oil;

	•	commodity processing, gathering and transportation availability;

	•	the level of imports of, and the price of, foreign natural gas and oil;

	•	the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

	•	domestic governmental regulations and taxes;

	•	the price and availability of alternative fuel sources;

	•	the availability of pipeline capacity;

	•	weather conditions;

	•	market uncertainty;

	•	political conditions or hostilities in natural gas and oil producing regions;

	•	worldwide economic conditions; and

	•	decreased demand for the use of natural gas and oil because of market concerns about global warming or changes in governmental policies and regulations due to climate change initiatives.

Further, because the majority of our proved reserves at December 31, 2005 were natural gas reserves, we are substantially more sensitive to changes in natural gas prices than we are to changes in oil prices. Declines in natural gas and oil prices would not only reduce revenue, but could reduce the amount of natural gas and oil that we can produce economically and, as a result, could adversely affect the financial results of our exploration and production business. Changes in natural gas and oil prices can have a significant impact on the calculation of our full cost ceiling test. A significant decline in natural gas and oil prices could result in a downward revision of our reserves and a write-down of the carrying value of our natural gas and oil properties, which could be substantial, and would negatively impact our net income and stockholders’ equity.


	*The success of our exploration and production business is dependent, in part, on factors that are beyond our control.*

The performance of our exploration and production business is dependent upon a number of factors that we cannot control, including:


	•	the results of future drilling activity;

	•	the availability of rigs, equipment and labor to support drilling activity and production operations;

	•	our ability to identify and precisely locate prospective geologic structures and to drill and successfully complete wells in those structures in a timely manner;

	•	our ability to expand our leased land positions in desirable areas, which often are subject to intensely competitive conditions;

	•	increased competition in the search for and acquisition of reserves;


	•	significant increases in future drilling, production and development costs, including drilling rig rates and oil field services costs;

	•	adverse changes in future tax policies, rates, and drilling or production incentives by state, federal, or foreign governments;

	•	increased federal or state regulations, including environmental regulations, that limit or restrict the ability to drill natural gas or oil wells, reduce operational flexibility, or increase capital and operating costs;

	•	our lack of control over jointly owned properties and properties operated by others;

	•	the availability of alternative sources of energy;

	•	declines in production volumes, including those from the Gulf of Mexico; and

	•	continued access to sufficient capital to fund drilling programs to develop and replace a reserve base with rapid depletion characteristics.


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

Our operations are subject to all the risks normally incident to the operation and development of natural gas and oil properties and the drilling of natural gas and oil wells, including well blowouts, cratering and explosions, pipe failure, fires, formations with abnormal pressures, uncontrollable flows of natural gas, oil, brine or well fluids, release of contaminants into the environment and other environmental hazards and risks. Additionally, our offshore operations may encounter usual marine perils, including hurricanes and other adverse weather conditions, damage from collisions with vessels, governmental regulations and interruption or termination by governmental authorities based on environmental and other considerations. Each of these risks could result in damage to property, injuries to people or the shut in of existing production as damaged energy infrastructure is repaired or replaced.

We maintain insurance coverage to reduce exposure to potential losses resulting from these operating hazards. The nature of the risks is such that some liabilities could exceed our insurance policy limits, or, as in the case of environmental fines and penalties, cannot be insured which could adversely affect our future results of operations, cash flows or financial condition.

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


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

Estimating quantities of proved natural gas and oil reserves is a complex process that involves significant interpretations and assumptions. It requires interpretations and judgment of available technical data, including the evaluation of available geological, geophysical, and engineering data. It also requires making estimates based upon economic factors, such as natural gas and oil prices, production costs, severance and excise taxes, capital expenditures, workover and remedial costs, and the assumed effect of governmental regulation. Due to a lack of substantial, if any, production data, there are greater uncertainties in estimating proved undeveloped reserves, proved non-producing reserves and proved developed reserves that are early in their production life. As a result, our reserve estimates are inherently imprecise. Also, we use a 10 percent discount factor for estimating the value of our reserves, as prescribed by the SEC, which may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our exploration and production business or the natural gas and oil industry, in general, are subject. Any significant variations from the interpretations or assumptions used in our estimates or changes of conditions could cause the estimated quantities and net present value of our reserves to differ materially.

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

A portion of our estimated proved reserves are undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data assumes that we can and will make these expenditures and conduct these operations successfully, but future events, including commodity price changes, may cause these assumptions to change.


	*The success of our exploration and production business depends upon our ability to replace reserves that we produce.*

Unless we successfully replace the reserves that we produce, our reserves will decline, eventually resulting in a decrease in natural gas and oil production and lower revenues and cash flows from operations. We historically have replaced reserves through both drilling and acquisitions. The business of exploring for, developing or acquiring reserves requires substantial capital expenditures. Our operations require continued access to sufficient capital to fund drilling programs to develop and replace a reserve base with rapid depletion characteristics. If we do not continue to make significant capital expenditures, or if our capital resources become limited, we may not be able to replace the reserves that we produce, which would negatively affect our future revenues, cash flows and results of operations.


	*We face competition from third parties to acquire and develop natural gas and oil reserves.*

The natural gas and oil business is highly competitive in the search for and acquisition of reserves. We must identify and precisely locate prospective geologic structures, drill and successfully complete wells in those structures in a timely manner. Our ability to expand our leased land positions in desirable areas is impacted by intensely competitive leasing conditions. Competition for reserves and producing natural gas and oil properties is intense and many of our competitors have financial and other resources that are substantially greater than those available to us. Our competitors include the major and independent natural gas and oil companies, individual producers, gas marketers and major pipeline companies, as well as participants in other industries supplying energy and fuel to industrial, commercial and individual consumers. If we are unable to compete effectively in the acquisition and development of reserves, our future profitability may be negatively impacted. Ultimately, our future success in the production business is dependent on our ability to find or acquire additional reserves at costs that allow us to remain competitive.


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

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

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

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


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

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


	*Our foreign operations and investments involve special risks.*

Our activities in areas outside the United States, including material investment exposure in our power, pipeline and exploration and production projects in Brazil (see Part II, Item 8, Financial Statements and Supplementary Data, Note 16), are subject to the risks inherent in foreign operations, including:


	•	loss of revenue, property and equipment as a result of hazards such as expropriation, nationalization, wars, insurrection and other political risks;

	•	the effects of currency fluctuations and exchange controls, such as devaluation of foreign currencies and other economic problems; and

	•	changes in laws, regulations and policies of foreign governments, including those associated with changes in the governing parties.


	*Retained liabilities associated with businesses that we have sold could exceed our estimates and we could experience difficulties in managing these liabilities.*

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

Risks Related to Legal and Regulatory Matters


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

We are subject to numerous governmental investigations including those involving allegations of round trip trades, price reporting of transactional data to the energy trade press, natural gas and oil reserve revisions, accounting treatment of certain hedges of our anticipated natural gas production, sales of crude oil of Iraqi origin under the United Nation’s Oil for Food Program and the rupture of one of our pipelines near Carlsbad, New Mexico. These investigations involve, among others, one or more of the following governmental agencies: the SEC, FERC, a grand jury of the U.S. District Court for the Southern District of New York, U.S. Senate Permanent Subcommittee of Investigations, the House of Representatives International Relations Subcommittee, the U.S. Department of Transportation Office of Pipeline Safety and the Department of Justice. We are cooperating with the governmental agency or agencies in each of these investigations. The outcome of each of these investigations is uncertain. Because of the uncertainties associated with the ultimate outcome of each of these investigations and the costs to the Company of responding and participating in these

on-going investigations, no assurance can be given that the ultimate costs and sanctions, if any, that may be imposed upon us will not have a material adverse effect on our business, financial condition or results of operation.


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

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

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

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


	*Environmental compliance and remediation costs and the costs of environmental liabilities could exceed our estimates.*

Our operations are subject to various environmental laws and regulations regarding compliance and remediation obligations. Compliance obligations can result in significant costs to install and maintain pollution controls, fines and penalties resulting from any failure to comply, and potential limitations on our operations. Remediation obligations can result in significant costs associated with the investigation and remediation or clean-up of contaminated properties (some of which have been designated as Superfund sites by the Environmental Protection Agency (EPA) under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA)), as well as damage claims arising out of the contamination of properties or impact on natural resources. It is not possible for us to estimate exactly the amount and timing of all future expenditures related to environmental matters because of:


	•	The uncertainties in estimating pollution control and clean up costs, including for sites for which only preliminary site investigation or assessments have been completed;

	•	The discovery of new sites or additional information at existing sites;

	•	The uncertainty in quantifying liability under environmental laws that impose joint and several liability on all potentially responsible parties; and

	•	The nature of environmental laws and regulations, including the interpretation and enforcement thereof.

Currently, various legislative and regulatory measures to address greenhouse gas (GHG) emissions (including carbon dioxide and methane) are in various phases of discussion or implementation. These include the Kyoto Protocol, proposed federal legislation and state actions to develop statewide or regional programs, each of which have imposed or would impose reductions in GHG emissions. These actions could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage any GHG emissions program. These actions could also impact the consumption of natural gas and oil, thereby affecting our pipeline and exploration and production operations.

Although we believe we have established appropriate reserves for our environmental liabilities, we could be required to set aside additional amounts due to these uncertainties which could significantly impact our future consolidated results of operations, cash flows or financial position. For additional information concerning our environmental matters, see Part I, Item 3, Legal Proceedings and Part II, Item 8, Financial Statements and Supplementary Data, Note 16.


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

We are involved in various lawsuits in which we or our subsidiaries have been sued. We also have other contingent liabilities and exposures. Although we believe we have established appropriate reserves for these liabilities, we could be required to set aside additional reserves in the future and these amounts could be material. For additional information concerning our litigation matters and other contingent liabilities, see Part II, Item 8, Financial Statements and Supplementary Data, Note 16.


	Our system of internal controls is designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes. A loss of public confidence in the quality of our internal controls or disclosures could have a negative impact on us.

Our system of internal controls is designed to provide reasonable assurance that the objectives of the control system are met. However, any system of internal controls is subject to inherent limitations and the design of our controls may not provide absolute assurances that all of our objectives will be entirely met. This includes the possibility that controls may be inappropriately circumvented or overridden, that judgments in decision-making can be faulty and that misstatements due to errors or fraud may not be prevented or detected.

Risks Related to Our Liquidity


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

We have significant debt, debt service and debt maturity obligations. The ratings assigned to our senior unsecured indebtedness are below investment grade, currently rated Caa1 by Moody’s Investor Service (Moody’s) and B- by Standard & Poor’s. These ratings have increased our cost of capital and our operating costs, particularly in our trading operations, and could impede our access to capital markets. Moreover, we must retain greater liquidity levels to operate our business than if we had investment grade credit ratings. If our ability to generate or access capital becomes significantly restrained, our financial condition and future results of operations could be significantly adversely affected. See Part II, Item 8, Financial Statements and Supplementary Data, Note 14, for a further discussion of our debt.

We may not achieve our targeted level of debt reduction or complete our asset sales in a timely manner or at all.

Our ability to achieve our announced targets to reduce our debt obligations and complete asset sales, as well as the timing of their achievement, is subject, in part, to factors beyond our control. These factors include our ability to locate potential buyers in a timely fashion and obtain a reasonable price, and our ability to preserve sufficient cash flow to service our debt and other obligations. If we fail to achieve these targets in a timely manner, our liquidity or financial position could be materially adversely affected. In addition, it is possible that our asset sales could be at prices that are below the current book value for the assets, which could result in losses that could be substantial.


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

Our debt and other financing obligations contain restrictive covenants, which become more restrictive over time, and cross-acceleration provisions. A breach of any of these covenants could preclude us or our subsidiaries from issuing letters of credit and from borrowing under our credit agreements, and could

accelerate our debt and other financing obligations and those of our subsidiaries. If this were to occur, we might not be able to repay such debt and other financing obligations.

Some of our credit agreements are collateralized by our equity interests in ANR, CIG, EPNG, Southern Gas Storage Company (which owns an interest in Bear Creek Storage Company), ANR Storage Company, TGP and certain natural gas and oil reserves. A breach of the covenants under these agreements could permit the lenders to exercise their rights to the collateral, and we could be required to sell these collateral interests.


	*We are subject to financing and interest rate exposure risks.*

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


	•	our credit ratings;

	•	interest rates;

	•	the structured and commercial financial markets;

	•	market perceptions of us or the natural gas and energy industry;

	•	tax rates due to new tax laws;

	•	our stock price; and

	•	market prices for energy.

In addition, although we hedge a portion of our exposure to interest rate movements, our financial condition and liquidity could be adversely affected if there is a negative movement in interest rates.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

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

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

ITEM 3. LEGAL PROCEEDINGS

Details of the cases listed below, as well as a description of our other legal proceedings are included in Part II, Item 8, Financial Statements and Supplementary Data, Note 16, and are incorporated herein by reference.

The shareholder class actions filed in the U.S. District Court for the Southern District of Texas, Houston Division, are: Marvin Goldfarb, et al v. El Paso Corporation, William Wise, H. Brent Austin, and Rodney D. Erskine, filed July 18, 2002; Residuary Estate Mollie Nussbacher, Adele Brody Life Tenant, et al v. El Paso Corporation, William Wise, and H. Brent Austin,filed July 25, 2002; George S. Johnson, et al v. El Paso Corporation, William Wise, and H. Brent Austin, filed July 29, 2002; Renneck Wilson, et al v. El Paso Corporation, William Wise, H. Brent Austin, and Rodney D. Erskine, filed August 1, 2002; and Sandra Joan Malin Revocable Trust, et al v. El Paso Corporation, William Wise, H. Brent Austin, and Rodney D. Erskine, filed August 1, 2002; Lee S. Shalov, et al v. El Paso Corporation, William Wise, H. Brent Austin, and Rodney D. Erskine, filed August 15, 2002; Paul C. Scott, et al v. El Paso Corporation, William Wise, H. Brent Austin, and Rodney D. Erskine,filed August 22, 2002; Brenda Greenblatt, et al v. El Paso Corporation, William Wise, H. Brent Austin, and Rodney D. Erskine, filed August 23, 2002; Stefanie Beck, et al v. El Paso Corporation, William Wise, and H. Brent Austin, filed August 23, 2002; J. Wayne Knowles, et al v. El Paso Corporation,

William Wise, H. Brent Austin, and Rodney D. Erskine, filed September 13, 2002; The Ezra Charitable Trust, et al v. El Paso Corporation, William Wise, Rodney D. Erskine and H. Brent Austin, filed October 4, 2002.

The shareholder class actions relating to our reserve restatement filed in the U.S. District Court for the Southern District of Texas, Houston Division, which have now been consolidated with the above referenced purported shareholder class actions, are: James Felton v. El Paso Corporation, Ronald Kuehn, Jr., Douglas Foshee and D. Dwight Scott; Sinclair Haberman v. El Paso Corporation, Ronald Kuehn, Jr., and William Wise; Patrick Hinner v. El Paso Corporation, Ronald Kuehn, Jr., Douglas Foshee, D. Dwight Scott and William Wise; Stanley Peltz v. El Paso Corporation, Ronald Kuehn, Jr., Douglas Foshee and D. Dwight Scott; Yolanda Cifarelli v. El Paso Corporation, Ronald Kuehn, Jr., Douglas Foshee and D. Dwight Scott; Andrew W. Albstein v. El Paso Corporation, William Wise; George S. Johnson v. El Paso Corporation, Ronald Kuehn, Jr., Douglas Foshee, and D. Dwight Scott; Robert Corwin v. El Paso Corporation, Mark Leland, Brent Austin, Ronald Kuehn, Jr., D. Dwight Scott and William Wise; Michael Copland v. El Paso Corporation, Ronald Kuehn, Jr., Douglas Foshee and D. Dwight Scott; Leslie Turbowitz v. El Paso Corporation, Mark Leland, Brent Austin, Ronald Kuehn, Jr., D. Dwight Scott and William Wise; David Sadek v. El Paso Corporation, Ronald Kuehn, Jr., Douglas Foshee, D. Dwight Scott; Stanley Sved v. El Paso Corporation, Ronald Kuehn, Jr., and William Wise; Nancy Gougler v. El Paso Corporation, Ronald Kuehn, Jr., Douglas Foshee and D. Dwight Scott; William Sinnreich v. El Paso Corporation, Ronald Kuehn, Jr., Douglas Foshee, D. Dwight Scott and William Wise; Joseph Fisher v. El Paso Corporation, Ronald Kuehn, Jr., Douglas Foshee, D. Dwight Scott and William Wise; Glickenhaus & Co. v. El Paso Corporation, Rod Erskine, Ronald Kuehn, Jr., Brent Austin, William Wise, Douglas Foshee and D. Dwight Scott; and Thompson v. El Paso Corporation, Ronald Kuehn, Douglas Foshee and D. Dwight Scott.

The stayed shareholder derivative actions filed in the United States District Court for the Southern District of Texas, Houston Division are Grunet Realty Corp. v. William A. Wise, Byron Allumbaugh, John Bissell, Juan Carlos Braniff, James Gibbons, Anthony Hall Jr., Ronald Kuehn Jr., J. Carleton MacNeil Jr., Thomas McDade, Malcolm Wallop, Joe Wyatt and Dwight Scott, filed August 22, 2002, and Russo v. William Wise, Brent Austin, Dwight Scott, Ralph Eads, Ronald Kuehn, Jr., Douglas Foshee, Rodney Erskine, PricewaterhouseCoopers and El Paso Corporation filed in September 2004. The consolidated shareholder derivative action filed in Houston is John Gebhart and Marilyn Clark v. El Paso Corporation, Byron Allumbaugh, John Bissell, Juan Carlos Braniff, James Gibbons, Anthony Hall Jr., Ronald Kuehn, Jr., J. Carleton MacNeil, Jr., Thomas McDade, Malcolm Wallop, William Wise, Joe Wyatt, Ralph Eads, Brent Austin and John Somerhalder filed in November 2002. Gebhardt Plaintiffs filed a Third Amended Petition in October 2005 adding additional defendants, James Dunlap, Douglas Foshee, Robert Goldman, Thomas Hix, William Joyce, Michael Talbert and John Whitmire. The two derivative actions filed in Delaware Chancery Court are Stephen Brudno, et al. v. William A. Wise, et al. filed in October 2002 (which was voluntarily dismissed in July 2005) and Alan Laties v. William Wise, John L. Bissell, Juan Carlos Braniff, James L. Dunlap, Douglas L. Foshee, Robert W. Goldman, Anthony Hall, Thomas R. Hix, William H. Joyce, Ronald L. Kuehn, Jr., J. Carlton MacNeil, Jr., J. Michael Talbert, John L. Whitmire, Joe B. Wyatt and El Paso Corporation. The Laties case was filed in April 2005 in Delaware Chancery Court nominally on behalf of El Paso against William Wise and the board of directors. An identical suit was filed by Laties in Harris County District Court on August 25, 2005, but has never been served on El Paso. The Laties case filed in Delaware was dismissed by the court in December 2005.

Environmental Proceedings

Air Permit Violation. In March 2003, the Louisiana Department of Environmental Quality (LDEQ) issued a Consolidated Compliance Order and Notice of Potential Penalty to our subsidiary, El Paso Production Company, alleging that it failed to timely obtain air permits for specified oil and natural gas facilities. El Paso Production Company requested an adjudicatory hearing on the matter. Pursuant to discussions with LDEQ, we have reached an agreement to resolve the allegations for $77,287. We signed the settlement agreement on November 28, 2005, and will pay the penalty once LDEQ has completed its approval process for this settlement.

Coastal Eagle Point Air Issues. On April 1, 2004, the New Jersey Department of Environmental Protection issued an Administrative Order and Notice of Civil Administrative Penalty Assessment seeking $183,000 in penalties for excess emission events that occurred during the fourth quarter of 2003 at our former

Eagle Point refinery. We filed an administrative appeal contesting the allegations and penalty. We reached an agreement to resolve the allegations and appeal for a penalty for $119,400, have executed the settlement agreement, and paid the agreed penalty in the fourth quarter of 2005, fully resolving this matter.

Corpus Christi Refinery Air Violations. On March 18, 2004, the Texas Commission on Environmental Quality (TCEQ) issued an “Executive Director’s Preliminary Report and Petition” seeking $645,477 in penalties relating to air violations alleged to have occurred at El Paso’s former Corpus Christi, Texas refinery from 1996 to 2000. We subsequently filed a hearing request to protect our procedural rights. In March 2005, the parties reached an agreement in principle to resolve the allegations for $272,097. In September 2005, the parties finalized the written terms of the settlement agreement. The final terms allow for $136,049 to be paid as a penalty and $136,049 to be spent on a supplemental environmental project. El Paso and TCEQ have executed the final agreement and all payments required to resolve this matter have been made.

EPNG State of Arizona Pipe-Coating. In September 2005, the Arizona Department of Environmental Quality (ADEQ) issued a Notice of Violation (NOV) for alleged regulatory violations related to our handling of asbestos-containing asphaltic pipe coating. We have been informed by the Attorney General for the State of Arizona, on behalf of the ADEQ, of its intent to assess a civil penalty and require preventive actions by us to resolve the NOV. Although the likely penalty and costs associated with any preventive actions are unknown at this time, the ADEQ proposed a fine of less than $1 million. We are in discussions with the state in an effort to resolve this matter.

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

Natural Buttes. In May 2003, we met with the EPA to discuss potential prevention of significant deterioration violations due to a de-bottlenecking modification at CIG’s facility. The EPA issued an Administrative Compliance Order and we were in negotiations with the EPA as to the appropriate penalty. In September 2005, we were informed that the EPA referred this matter to the U.S. Department of Justice (DOJ). We have since entered into a tolling agreement with the DOJ in order to facilitate continuing settlement discussions.

Shoup Natural Gas Processing Plant. On December 16, 2003, El Paso Field Services, L.P. received a Notice of Enforcement (NOE) from the TCEQ concerning alleged Clean Air Act violations at its Shoup, Texas plant. The alleged violations pertained to emission limit, testing, reporting and recordkeeping issues in 2001. On December 29, 2004, TCEQ issued an Executive Director’s Preliminary Report and Petition revising the allegations from the NOE and seeking a penalty of $419,650. We answered the Petition disputing the allegations and the penalty. We have reached an agreement to resolve the matter by agreeing to pay a penalty of $106,439 and conduct a supplemental environmental project costing $95,961. We paid the penalty to TCEQ and will perform the supplemental environmental project upon final execution of the settlement by TCEQ.

Tucson Waste Management. In September 2004, we received a NOV from the ADEQ for alleged failure to comply with waste management regulations at EPNG’s Tucson compressor station. EPNG fulfilled their request for information and documentation related to the alleged noncompliance. This matter has been referred to the Office of the Attorney General for the State of Arizona, has informed us of its intent to require a civil penalty to resolve the NOV. The amount of the penalty is unknown at this time, but we are in discussions with the State in an effort to resolve this matter.


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

None.

PART II


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

Our common stock is traded on the New York Stock Exchange under the symbol EP. As of February 24, 2006, we had 44,220 stockholders of record, which does not include beneficial owners whose shares are held by a clearing agency, such as a broker or bank.

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


		High		Low		Dividends

2005
	Fourth Quarter	$	14.07	$	10.78	$	0.04
	Third Quarter		14.16		11.13		0.04
	Second Quarter		11.87		9.30		0.04
	First Quarter		13.15		10.01		0.04
2004
	Fourth Quarter	$	11.85	$	8.42	$	0.04
	Third Quarter		9.20		7.37		0.04
	Second Quarter		7.95		6.58		0.04
	First Quarter		9.88		6.57		0.04

On February 14, 2006, we declared a quarterly dividend of $0.04 per share of our common stock, payable on April 3, 2006, to shareholders of record as of March 3, 2006. Future dividends will depend on business conditions, earnings, our cash requirements and other relevant factors.

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 apart 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.

Odd-lot Sales Program

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

ITEM 6. 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 Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and Part II, Item 8, Financial Statements and Supplementary Data included in this Report on Form 10-K. These selected historical results are not necessarily indicative of results to be expected in the future.


		As of or for the Year Ended December 31,

		2005			2004			2003			2002			2001

		(In millions, except per common share amounts)
Operating Results Data:
	Operating revenues⁽¹⁾	$	4,017		$	5,539		$	6,339		$	6,455		$	9,871
	Loss from continuing operations⁽²⁾	$	(702	)	$	(829	)	$	(605	)	$	(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	$	(1.13	)	$	(1.30	)	$	(1.01	)	$	(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			20,275			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 Part II, Item 8, Financial Statements and Supplementary Data, Note 3.
⁽²⁾		We incurred net losses of $0.4 billion 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 Part II, Item 8, 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.

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

Our Management’s Discussion and Analysis includes forward-looking statements that are subject to risks and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed beginning on page 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. Our operating results for all periods presented reflect 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 $0.6 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.

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 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	$	19,196
Principal amounts borrowed		1,638
Repayment/retirement of principal		(1,912	)
Sale of entities⁽¹⁾		(575	)
Other		(113	)

Total debt as of December 31, 2005	$	18,234


⁽¹⁾	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			$	(0.7	)	$	(0.8	)
		Non-cash income items				1.6			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			(0.5	)

			Total cash flow from operations		$	0.3		$	1.1

Other cash inflows
	Continuing investing activities
		Net proceeds from the sale of assets and investments			$	1.4		$	1.9
		Net proceeds from restricted cash				0.1			0.6
		Other				0.2			0.1

						1.7			2.6

	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			1.0

						2.9			2.4

			Total other cash inflows		$	4.6		$	5.0


					2005		2004

					(In billions)
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				1.7		2.5
		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
		Other				—		0.1

						2.1		3.6

			Total other cash outflows			4.9		5.4

				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 $0.8 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 $0.3 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 $1.1 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 $0.8 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 $1.7 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 Part II, Item 8, 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, 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 Part II, Item 8, 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	$	1,211	$	781	$	676	$	2,479	$	2,058	$	11,085	$	18,290
	Interest		1,316		1,281		1,212		1,145		945		10,939		16,838
Other contractual liabilities⁽²⁾			101		47		32		15		12		50		257
Operating leases⁽³⁾			81		71		14		11		7		33		217
Other contractual commitments and purchase obligations:⁽⁴⁾
	Transportation and storage⁽⁵⁾		112		100		94		91		89		368		854
	Commodity purchases⁽⁶⁾		33		32		21		14		14		28		142
	Other⁽⁷⁾		377		48		52		22		22		41		562

	Total contractual obligations	$	3,231	$	2,360	$	2,101	$	3,777	$	3,147	$	22,544	$	37,160


⁽¹⁾	See Part II, Item 8, Financial Statements and Supplementary Data, Note 14.
⁽²⁾	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.
⁽³⁾	See Part II, Item 8, Financial Statements and Supplementary Data, Note 16.
⁽⁴⁾	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.
⁽⁵⁾	These are commitments for demand charges for firm access to natural gas transportation and storage capacity.
⁽⁶⁾	Includes purchase commitments for natural gas and power.
⁽⁷⁾	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

Total

Less Than

1 to 3

4 to 5

6 to 10

Beyond

Fair

1 Year

Years

10 Years

Value

(In millions)

Derivatives designated as hedges⁽¹⁾


		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.

El Paso Corp/DE · 10-K · For 12/31/05

Filed On 3/7/06 5:29pm ET · SEC File 1-14365 · Accession Number 950129-6-2345

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