##### Table of Contents



UNITED STATES
 SECURITIES AND EXCHANGE
    COMMISSION
 Washington, D.C. 20549
      Form 10-K
  (Mark One)þ

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
    THE SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended
    December 31, 2006ORo

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
    THE SECURITIES EXCHANGE ACT OF 1934For the transition period
    from          to          .  Commission File Number 1-14365
 El Paso
    Corporation
 (Exact Name of Registrant as
    Specified in Its Charter)
  Delaware

76-0568816(State or Other Jurisdiction of
    Incorporation or Organization)

(I.R.S. Employer
    Identification No.)El Paso Building
    1001 Louisiana Street
    Houston, Texas

77002(Address of Principal Executive
    Offices)

(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 ExchangeTitle of Each Class

on which RegisteredCommon Stock, par value
    $3 per share

New York Stock Exchange   Securities registered pursuant to Section 12(g) of the
    Act: None
  þ o
  o þ
  þ o
  Regulation S-K Form 10-K Form 10-K. þ
  Rule 12b-2
 Large
    accelerated filer þ
    Accelerated
    filer o
    Non-accelerated
    filer o  Rule 12b-2 o þ
  State the aggregate market value of the voting and non-voting
    common equity held by non-affiliates of the registrant.
    Indicate the number of shares outstanding of each of the
    registrants classes of common stock, as of the latest
    practicable date.
    Documents
    Incorporated by Reference
  Form 10-K




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##### 



EL PASO
    CORPORATION
  TABLE OF
    CONTENTS
  Caption

PagePART IItem 1.

Business


1Item 1A.

Risk
    Factors


22Item 1B.

Unresolved Staff
    Comments


31Item 2.

Properties


31Item 3.

Legal
    Proceedings


31Item 4.

Submission of
    Matters to a Vote of Security Holders


31PART IIItem 5.

Market for
    Registrants Common Equity, Related Stockholder Matters and
    Issuer Purchases of Equity Securities


32Item 6.

Selected Financial
    Data


34Item 7.

Managements
    Discussion and Analysis of Financial Condition and Results of
    Operations


35Item 7A.

Quantitative and
    Qualitative Disclosures About Market Risk


74Item 8.

Financial
    Statements and Supplementary Data


77Item 9.

Changes in and
    Disagreements with Accountants on Accounting and Financial
    Disclosure


149Item 9A.

Controls and
    Procedures


149Item 9B.

Other
    Information


149PART IIIItem 10.

Directors,
    Executive Officers and Corporate Governance


150Item 11.

Executive
    Compensation


150Item 12.

Security Ownership
    of Certain Beneficial Owners and Management and Related
    Stockholder Matters


150Item 13.

Certain
    Relationships and Related Transactions, and Director
    Independence


150Item 14.

Principal
    Accountant Fees and Services


150PART IVItem 15.

Exhibits and
    Financial Statement Schedules


150Signatures


152Amendment No. 1 to the Amended and Restated Credit AgreementRatio of Earnings to Combined Fixed Charges and Preferred Stock DividendsSubsidiariesConsent of Independent Registered Public Accounting FirmConsent of Independent Registered Public Accounting FirmConsent of Ryder Scott Company, L.P.Certification of CEO Pursuant to Section 302Certification of CFO Pursuant to Section 302Certification of CEO Pursuant to Section 906Certification of CFO Pursuant to Section 906Ryder Scott Reserve Report for El Paso Exploration & Production CompanyRyder Scott Reserve Report for Four Star Oil & Gas Company      /d

=

per dayBbl

=

barrelBBtu

=

billion British thermal unitsBcf

=

billion cubic feetBcfe

=

billion cubic feet of natural gas
    equivalentsLNG

=

liquefied natural gasMBbls

=

thousand barrelsMcf

=

thousand cubic feetMcfe

=

thousand cubic feet of natural gas
    equivalents  MDth

=

thousand dekathermsMMBtu

=

million British thermal unitsMMcf

=

million cubic feetMMcfe

=

million cubic feet of natural gas
    equivalentsGWh

=

thousand megawatt hoursMW

=

megawattNGL

=

natural gas liquidsTBtu

=

trillion British thermal unitsTcfe

=

trillion cubic feet of natural gas
    equivalents     and/or
 i




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##### Table of Contents



PART I  ITEM 1.
    BUSINESS  Business
    and Strategy    Regulated Natural Gas Transmission.
  Exploration and Production.
    Pipelines
    Segment
        
    Expanding our systems by attracting new customers, markets or
    supply sources;
    Identifying and developing growth opportunities;
    Recontracting or contracting available or expiring capacity; 1




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##### Table of Contents




    Focusing on efficiency in our operations and cost control,
    including efficiencies that may be available across our systems;
    Maintaining the value and ensuring the safety of our pipeline
    systems and assets; and
    Providing outstanding customer service.  Wholly
    Owned Interstate Transmission Systems  As of December 31, 2006Transmission

Supply and

Miles of


Design


Storage


Average
    Throughput(1)System

Market Region

Pipeline


Capacity


Capacity


2006


2005


2004(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



6,961



90



4,534



4,443



4,469ANR
    Pipeline(2)(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



7,311



197



3,954



4,100



4,067El Paso Natural Gas (EPNG)

Extends from 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.


10,300



5,650(3
)


44



4,179



4,053



4,074Southern Natural
    Gas (SNG)

Extends from natural gas fields in
    Texas, Louisiana, Mississippi, Alabama and the Gulf of Mexico to
    Louisiana, Mississippi, Alabama, Florida, Georgia, South
    Carolina and Tennessee, including the metropolitan areas of
    Atlanta and Birmingham.


7,500



3,450



60



2,211



1,984



2,163Colorado
    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



2,008



1,902



1,744Wyoming
    Interstate
    (WIC)

Extends from western Wyoming,
    western Colorado and the Powder River Basin to various pipeline
    interconnections near Cheyenne, Wyoming.


700



2,330







1,914



1,572



1,214 2




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##### Table of Contents



As of December 31, 2006Transmission

Supply and

Miles of


Design


Storage


Average
    Throughput(1)System

Market Region

Pipeline


Capacity


Capacity


2006


2005


2004(MMcf/d)


(Bcf)





(BBtu/d)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 to customers in the vicinity of Bakersfield,
    California.


400



407







461



161



161Cheyenne Plains Gas
    Pipeline(4)(CPG)

Extends from Cheyenne hub in
    Colorado to various pipeline interconnections near Greensburg,
    Kansas.


400



838







583



433



89     (1)
    
    Includes throughput transported on
    behalf of affiliates.(2)
    
    Sold in February 2007.(3)
    
    This capacity reflects
    winter-sustainable west-flow capacity of 4,850 MMcf/d and
    approximately 800 MMcf/d of east-end delivery capacity.(4)
    
    This system was completed in 2005.    Capacity




AnticipatedProject

(MMcf/d)


Description

Completion DateLouisiana Deepwater Link


850


To construct a 300 foot extension
    of our
    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 Product Partners  Independence Hub
    platform located in Mississippi Canyon Block 920.

July 2007Triple-T Extension


200


To construct 6.2 miles of
    24-inch
    pipeline to extend our existing
    30-inch
    Triple-T Line, beginning in Eugene Island Block 349, to
    interconnect with Enterprise Products Partners L.P.s
    Anaconda System on the El 371 platform, as well as associated
    piping and other appurtenant facilities.

September 2007Essex Middlesex Project


80


To construct 7.8 miles of
    24-inch
    pipeline connecting our Beverly-Salem line to the DOMAC line in
    Essex and Middlesex Counties, Massachusetts.

November 2007Northeast ConneXion 
    New England


108


To construct a compression station
    and modify compression at six existing facilities on our
    interstate pipeline system in Pennsylvania, New York, and
    Massachusetts.

November 2007Cypress Expansion


500


To construct approximately
    177 miles of pipeline to connect our Elba Island facility
    with markets in Georgia and Florida.

May
    2007(1)     (1)
    
    Project will consist of three
    phases. The anticipated completion date is related to
    phase 1. 3




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##### Table of Contents



Partially
    Owned Interstate Transmission Systems  As of December 31, 2006Transmission

Supply and

Ownership


Miles of


Design


Average
    Throughput(2)System(1)

Market Region

Interest


Pipeline(2)


Capacity(2)


2006


2005


2004(Percent)





(MMcf/d)


(BBtu/d)Florida Gas
    Transmission(3)

Extends from South Texas to South
    Florida.


50



4,868



2,090



2,018



1,916



2,014Great Lakes Gas
    Transmission(4)

Extends from Manitoba-Minnesota
    border to the Michigan-Ontario border at St. Clair, Michigan.


50



2,115



2,600



2,244



2,376



2,200Samalayuca Pipeline and Gloria a
    Dios Compression Station

Extends from
    U.S.-Mexico
    border to the state of Chihuahua, Mexico.


50



23



460



442



423



433San 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



951     (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 Corp. (Citrus), which owns this system.(4)
    
    Sold in February 2007.  Partially
    Owned Intrastate Transmission Systems    Underground
    Natural Gas Storage Entities    As of December 31, 2006Ownership


StorageStorage Entity

Interest


Capacity(1)


Location(Percent)


(Bcf)Bear Creek Storage


100



58



LouisianaANR
    Storage(2)


100



56



MichiganBlue Lake Gas
    Storage(2)


75



47



MichiganEaton Rapids Gas
    Storage(2)(3)


50



13



MichiganYoung Gas
    Storage(3)


48



6



Colorado     (1)
    
    Approximately 135 Bcf is
    contracted to affiliates. Amounts are not adjusted for our
    ownership interest.(2)
    
    Sold in February 2007.(3)
    
    This system is accounted for as an
    equity investment.  LNG
    Facility   4




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##### Table of Contents



Markets
    and Competition          Contract
    Expirations(1)
  
 (1) Includes ANR sold in February 2007.
   5




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##### Table of Contents



TGPCustomer Information

Contract Information

CompetitionApproximately 460 firm and
    interruptible customers, none of which individually represents
    more than 10 percent of revenues

Approximately 470 firm
    transportation contracts. Weighted average remaining contract
    term of approximately four years.

TGP faces competition in its
    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 the TGP system._
    _ANR(1)Customer
    Information

Contract
    Information

CompetitionApproximately 290 firm and
      interruptible customers 
     Major Customer:
      We Energies
         (799 BBtu/d)

Approximately 670 firm
    transportation contracts. Weighted average remaining contract
    term of approximately five years.
     Expire in 2007-2016.

In its market areas, ANR competes directly with Guardian Pipeline, for markets in Wisconsin. ANR also competes directly with other interstate pipelines in the northeast markets to serve electric generation and local distribution companies. In its supply areas, ANR 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.(1)Sold in February
    2007_
    _EPNGCustomer
    Information

Contract
    Information

CompetitionApproximately 160 firm and
      interruptible customers 
     Major Customers:
      Southern California Gas Company
         (101 BBtu/d)
         (187 BBtu/d)
         (561 BBtu/d)

Approximately 190 firm
    transportation contracts. Weighted average remaining contract
    term of approximately four years.
     Expires in 2007.
     Expires in 2009.
     Expire in 2010 - 2011.
     Expires in 2008.
     Expire in 2011 - 2015.

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,
    nuclear, wind, coal and fuel oil. In addition, construction of
    facilities to bring LNG into California and northern Mexico are
    underway.Southwest Gas
    Corporation(11
    BBtu/d)(476
    BBtu/d) 6




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##### Table of Contents



_
    _SNGCustomer
    Information

Contract
    Information

CompetitionApproximately 274 firm and
      interruptible customers 
     Major Customers:
      Atlanta Gas Light Company
         (959 BBtu/d)
      Southern Company Services
         (418 BBtu/d)

Approximately 200 firm
    transportation contracts. Weighted average remaining contract
    term of approximately six years.
      Expire in 2009-2015.
      Expire in 2010-2018.
      Expire in 2010-2013.
      Expire in 2007-2019.

SNG faces 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 SNGs system competes with alternative
    energy sources used to generate electricity, such as
    hydroelectric power, nuclear 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.Alabama Gas
    Corporation(413
    BBtu/d)Scana Corporation(316
    BBtu/d)_
    _CIGCustomer
    Information

Contract
    Information

CompetitionApproximately 110 firm and
    interruptible customers
     Major Customers:
      Public Service Company of Colorado
         (187 BBtu/d)
         (9 BBtu/d)
         (1,106 BBtu/d)
      Williams Power Company
         (30 BBtu/d)
         (53 BBtu/d)
         (348 BBtu/d)

Approximately 170 firm
    transportation contracts. Weighted average remaining contract
    term of approximately six years.
     Expires in 2008.
     Expires in 2009.
     Expire in 2012-2014. 
     Expires in 2007.
     Expires in 2009.
     Expire in 2010 -  2013.
     Expires in 2007.
     Expires in 2008.
     Expires in 2009.
     Expire in 2010 - 2015.

CIG serves two major markets, an
    on- system market and an off-
    system market. Its on-system market consists
    of utilities and other customers located along the front range
    of the Rocky Mountains in Colorado and Wyoming. Competitors in
    this market consist of an intrastate pipeline, a new interstate
    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. CIGs 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 this off- system market consists of a
    new interstate pipeline and other existing interstate pipelines
    that are directly connected to its supply sources.Anadarko Petroleum
    Corporation and     subsidiaries(10
    BBtu/d)(60
    BBtu/d)(12
    BBtu/d)(208
    BBtu/d) 7




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##### Table of Contents



_
    _WICCustomer
    Information

Contract
    Information

CompetitionApproximately 50 firm and
      interruptible customers 
     Major Customers:
      Williams Power Company
         (25 BBtu/d)

Approximately 50 firm
    transportation contracts. Weighted average remaining contract
    term of approximately six years.
     Expires in 2008.
     Expire in 2010-2021.
     Expires in 2008.
     Expire in 2011-2017.

WIC competes with existing
    pipelines and a new interstate pipeline to provide
    transportation services to pipeline interconnects in northeast
    Colorado and western Wyoming.(678
    BBtu/d)
     Anadarko Petroleum Corporation and  subsidiaries(25
    BBtu/d)(385
    BBtu/d)_
    _MPCCustomer
    Information

Contract
    Information

CompetitionApproximately 20 firm and
     interruptible customers
     Major Customers:
      Los Angeles Department of Water
         and Power
         (50 BBtu/d)

Approximately six firm
    transportation contracts. Weighted average remaining contract
    term of approximately seven years.
     Expires in 2015.
     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,
    nuclear, wind, coal and fuel oil. In addition, construction of
    facilities to bring LNG into California and northern Mexico are
    underway.EPNG(312
    BBtu/d)Los Angeles Department
    of Waterand
    Power(50
    BBtu/d)_
    _CPGCustomer
    Information

Contract
    Information

CompetitionApproximately 30 firm and
     interruptible customers
     Major Customers:
      Oneok Energy Services
         Company L.P.
         (195 BBtu/d)

Approximately 30 firm
    transportation contracts. Weighted average remaining contract
    term of approximately eight years.
     Expire in 2015. 
     Expire in 2015.
     Expire in 2015-2016.

CPG competes directly with other
    interstate pipelines serving the mid- continent region.
    Indirectly, CPG competes with pipelines that are existing and
    currently under construction to transport Rocky Mountain gas to
    other markets.Encana Marketing(USA)
    Inc.(170
    BBtu/d)Anadarko Petroleum
    Corporation(195
    BBtu/d)  8




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##### Table of Contents



Exploration
    and Production Segment
    United
    States
  Onshore.
  2006AverageNet


Capital

ProductionRegion

Description

Acres


Investment

(MMcfe/d)East Texas/north Louisiana
    (Arklatex)

Concentrated land position
    primarily focused on tight gas sands production in the Travis
    Peak/Hosston and Cotton Valley formations.


104,000


$203 million


122Black Warrior Basin

Established shallow coal bed
    methane producing areas of northwestern Alabama. We have high
    average working interests in our operated properties in addition
    to an average 50 percent working interest covering
    approximately 46,000 net acres operated by Black Warrior
    Methane which produces from the Brookwood Field.


172,000


$49 million


64Mid-Continent

Primarily in Oklahoma with a focus
    on development projects in the Arkoma Basin where we utilize
    horizontal drilling in the Hartshorne Coals area, West Verdon
    field, an oil producing waterflood project and shallow natural
    gas production in the Hugoton field.


319,000


$56 million


28Rocky Mountain (Rockies)

Primarily in Wyoming and Utah with
    a focus in the Powder River and Uintah basins, consisting
    predominantly of operated oil fields utilizing both primary and
    secondary recovery methods combined with non-operated coal bed
    methane fields. We also operate the Altamont and Bluebell
    processing plants and related gathering systems in Utah.


364,000


$120 million


55Raton Basin

Primarily focused on coal bed
    methane production in northern New Mexico and southern Colorado
    where we own the minerals and have a 100 percent working
    interest in the Vermejo Park Ranch.


605,000


$72 million


76    9




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##### Table of Contents



Texas Gulf Coast.
  2006AverageCapital

ProductionRegion

Description

Net Acres


Investment

(MMcfe/d)Vicksburg/Frio Trends

Includes concentrated and
    contiguous assets, located in south Texas, including the
    Jeffress and Monte Christo fields primarily in Hidalgo county,
    in which we have an average 90 percent working interest.


81,000


$111 million


123Upper Gulf Coast Wilcox

Located onshore Texas Gulf Coast,
    including Renger, Dry Hollow and Speaks fields in Lavaca County.
    In this area, average well depth is between 13,000 to
    18,000 feet.


31,000


$60 million


32South Texas Wilcox

Includes the Bob West and Roleta
    fields in Zapata County where in January 2007 we completed the
    acquisition described below.


25,000


$29 million


27     Gulf of Mexico Shelf and south Louisiana.
  2006AverageCapital

ProductionRegion

Description

Net Acres


Investment

(MMcfe/d)Gulf of Mexico Shelf

Primarily deep shelf drilling
    interests in 173 Blocks (generally nine square miles) south of
    the Louisiana, Texas and Alabama shorelines focused on deep
    (greater than 12,000 feet) gas reserves in relatively
    shallow waters depths (less than 400 feet).


688,000


$246 million


163South Louisiana

Primarily in Vermillion Parish and
    associated bays and waters in southwestern Louisiana covered by
    the Catapult 3D seismic project. We have internally processed
    2,600 square miles of contiguous 3D seismic data in this
    project.


34,000


$64 million


11  10




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##### Table of Contents



Unconsolidated Investment in Four Star.
  International
  Brazil.
  Egypt.
 11




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##### Table of Contents



Natural
    Gas and Oil Properties
  Natural
    Gas, Oil and Condensate and NGL Reserves and
    Production
    Net Proved Reserves


2006Natural Gas


Oil/Condensate


NGL


Total


Production(MMcf)


(MBbls)


(MBbls)


(MMcfe)


(Percent)


(MMcfe)Reserves and Production by
    RegionUnited StatesOnshore


1,308,742



28,947



1,060



1,488,789



62
%


126,093Texas Gulf Coast


344,596



2,265



8,004



406,209



17
%


68,269Gulf of Mexico Shelf and south
    Louisiana


209,897



9,467



948



272,384



11
%


63,537Total United States


1,863,235



40,679



10,012



2,167,382



90
%


257,899Brazil


56,383



31,847







247,466



10
%


8,619Total


1,919,618



72,526



10,012



2,414,848



100
%


266,518Unconsolidated investment in Four
    Star


167,046



2,947



6,209



221,984



100
%


24,663Reserves by ClassificationUnited StatesProducing


1,251,019



22,415



7,402



1,429,923



66
%Non-Producing


217,881



7,201



1,263



268,665



12
%Undeveloped


394,335



11,063



1,347



468,794



22
%Total proved


1,863,235



40,679



10,012



2,167,382



100
%BrazilProducing


19,931



489







22,864



9
%Non-Producing


3,405



335







5,418



2
%Undeveloped


33,047



31,023







219,184



89
%Total proved


56,383



31,847







247,466



100
%WorldwideProducing


1,270,950



22,904



7,402



1,452,787



60
%Non-Producing


221,286



7,536



1,263



274,083



11
%Undeveloped


427,382



42,086



1,347



687,978



29
%Total proved


1,919,618



72,526



10,012



2,414,848



100
%Unconsolidated investment in
    Four StarProducing


136,489



2,874



5,068



184,140



83
%Non-Producing


2,733







26



2,892



1
%Undeveloped


27,824



73



1,115



34,952



16
%Total Four Star


167,046



2,947



6,209



221,984



100
%  12




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##### Table of Contents



Form 10-K.
        Acreage
    and Wells
    Developed


Undeveloped


TotalAcreage

Gross(1)


Net(2)


Gross(1)


Net(2)


Gross(1)


Net(2)United StatesOnshore


874,525



556,828



1,612,025



1,135,010



2,486,550



1,691,838Texas Gulf Coast


93,573



73,373



91,230



63,452



184,803



136,825Gulf of Mexico Shelf and south
    Louisiana


508,716



359,064



401,075



363,046



909,791



722,110Total


1,476,814



989,265



2,104,330



1,561,508



3,581,144



2,550,773Brazil


49,262



17,242



1,158,643



343,563



1,207,905



360,805Egypt










64,740



12,948



64,740



12,948Worldwide Total


1,526,076



1,006,507



3,327,713



1,918,019



4,853,789



2,924,526  13




---



##### Table of Contents



Wells Being Drilled at December 31,Natural Gas


Oil


Total


2006Productive Wells

Gross(1)


Net(2)


Gross(1)


Net(2)


Gross(1)


Net(2)(3)


Gross(1)


Net(2)United StatesOnshore


3,880



2,954



801



548



4,681



3,502



52



38Texas Gulf Coast


843



703











843



703



6



5Gulf of Mexico Shelf and south
    Louisiana


187



122



58



40



245



162



6



4Total


4,910



3,779



859



588



5,769



4,367



64



47Brazil


4



1



6



2



10



3







Worldwide Total


4,914



3,780



865



590



5,779



4,370



64



47   Net
    Exploratory(2)


Net
    Development(2)Wells Drilled

2006


2005


2004


2006


2005


2004United StatesProductive


106



86



13



319



279



298Dry


6



2



10



2



4



3Total


112



88



23



321



283



301BrazilProductive






















Dry










1











Total










1











WorldwideProductive


106



86



13



319



279



298Dry


6



2



11



2



4



3Total


112



88



24



321



283



301     (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 wells drilled.(3)
    
    At December 31, 2006, we
    operated 3,957 of the 4,370 net productive wells.   14




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##### Table of Contents



Net
    Production, Sales Prices, Transportation and Production
    Costs
    2006


2005


2004Consolidated Volumes, Prices,
    and Costs per Unit:Net Production VolumesUnited StatesNatural gas (MMcf)


213,262



206,714



238,009Oil, condensate and NGL (MBbls)


7,439



7,516



8,498Total (MMcfe)


257,899



251,807



288,994Brazil(1)Natural gas (MMcf)


7,140



15,578



6,848Oil, condensate and NGL (MBbls)


247



620



320Total (MMcfe)


8,619



19,300



8,772WorldwideNatural gas (MMcf)


220,402



222,292



244,857Oil, condensate and NGL (MBbls)


7,686



8,136



8,818Total (MMcfe)


266,518



271,107



297,766Total (MMcfe/d)


730



743



814Natural Gas Average Realized Sales
    Price ($/Mcf)United StatesExcluding hedges

$
6.77


$
7.92


$
6.02Including hedges

$
6.50


$
6.69


$
5.94BrazilExcluding hedges

$
2.61


$
2.33


$
2.01Including hedges

$
2.61


$
2.33


$
2.01WorldwideExcluding hedges

$
6.64


$
7.53


$
5.90Including hedges

$
6.38


$
6.39


$
5.83Oil, Condensate, and NGL Average
    Realized Sales Price ($/Bbl)United StatesExcluding hedges

$
55.95


$
45.86


$
34.44Including hedges

$
55.95


$
45.86


$
34.44BrazilExcluding hedges

$
64.02


$
53.42


$
43.01Including hedges

$
54.48


$
42.42


$
39.19WorldwideExcluding hedges

$
56.21


$
46.43


$
34.75Including hedges

$
55.90


$
45.60


$
34.61Average Transportation CostUnited StatesNatural gas ($/Mcf)

$
0.24


$
0.20


$
0.17Oil, condensate and NGL ($/Bbl)

$
0.85


$
0.69


$
1.16WorldwideNatural gas ($/Mcf)

$
0.23


$
0.18


$
0.17Oil, condensate and NGL ($/Bbl)

$
0.82


$
0.63


$
1.12Average Production
    Cost($/Mcfe)(2)United StatesAverage lease operating cost

$
0.97


$
0.73


$
0.62Average production taxes


0.28



0.27



0.11Total production cost

$
1.25


$
1.00


$
0.73 15




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##### Table of Contents



2006


2005


2004BrazilAverage lease operating cost

$
0.28


$
0.42


$
Average production taxes


0.53







Total production cost

$
0.81


$
0.42


$
WorldwideAverage lease operating cost

$
0.95


$
0.72


$
0.60Average production taxes


0.29



0.24



0.11Total production cost

$
1.24


$
0.96


$
0.71Unconsolidated affiliate
    volumes (Four
    Star)(3)Natural gas (MMcf)


18,140



6,689Oil, condensate and NGL (MBbls)


1,087



359Total equivalent volumesMMcfe


24,663



8,844MMcfe/d


68



24     (1)
    
    Production volumes in Brazil
    decreased due to a contractual reduction of our ownership
    interest in the Pescada-Arabaiana Field in 2006.(2)
    
    Production cost includes lease
    operating costs and production related taxes (including ad
    valorem and severance taxes).(3)
    
    Includes our proportionate share of
    volumes in Four Star which was acquired in the third quarter of
    2005.  Acquisition,
    Development and Exploration Expenditures
    2006


2005


2004(In millions)United StatesAcquisition Costs:Proved

$
2


$
643


$
33Unproved


34



143



32Development Costs


738



503



395Exploration Costs:Delay rentals


6



3



7Seismic acquisition and
    reprocessing


23



7



29Drilling


294



133



149Asset Retirement Obligations


3



1



30Total full cost pool expenditures


1,100



1,433



675Non-full cost pool expenditures


8



22



11Total cost
    incurred(1)

$
1,108


$
1,455


$
686Acquisition of unconsolidated
    investment in Four
    Star(1)

$



$
769


$
Brazil and Other InternationalAcquisition Costs:Proved

$
2


$
8


$
69Unproved


1



1



3Development Costs


40



6



1Exploration Costs:Seismic acquisition and
    reprocessing


7



7



15Drilling


46



8



10 16




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##### Table of Contents



2006


2005


2004(In millions)Asset Retirement Obligations










3Total full cost pool expenditures


96



30



101Non-full cost pool expenditures










3Total cost incurred

$
96


$
30


$
104WorldwideAcquisition Costs:Proved

$
4


$
651


$
102Unproved


35



144



35Development Costs


778



509



396Exploration Costs:Delay rentals


6



3



7Seismic acquisition and
    reprocessing


30



14



44Drilling


340



141



159Asset Retirement Obligations


3



1



33Total full cost pool expenditures


1,196



1,463



776Non-full cost pool expenditures


8



22



14Total cost
    incurred(1)

$
1,204


$
1,485


$
790Acquisition of unconsolidated
    investment in Four
    Star(1)

$



$
769


$
     (1)
    
    In 2005, amount 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.    Markets
    and Competition
     17




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##### Table of Contents



Marketing
    Segment
    
    Production-Related Natural Gas and Oil
    Derivatives.  Includes options that provide price
    protection on our Exploration and Production segments
    natural gas and oil production.
    Natural Gas Transportation-Related
    Contracts.  Includes contracts that provide
    transportation capacity primarily with our affiliates.
    Historical Natural Gas and Power
    Contracts.  Includes supply agreements with
    Midland Cogeneration Venture and power contracts in the
    Pennsylvania-New Jersey-Maryland region.  Production-Related
    Natural Gas and Oil Derivatives
    2007


2008


2009Natural Gas (TBtu)Volumes with floor price


89



18



17Volumes with ceiling price






18



17Oil (MBbls)Volumes with floor and ceiling
    prices


1,009



930



   Contracts
    Related to Historical Trading Operations
  Natural gas transportation-related
    contracts.
  Alliance Pipeline

Affiliated
    Pipelines(1)

Other PipelinesDaily capacity (MMBtu/d)

160,000

521,000

156,000Expiration

October 31,
    2007(2)

2008 to 2028

2007 to 2026Receipt points

AECO Canada

Various

VariousDelivery points

Chicago

Various

Various     (1)
    
    Primarily consists of contracts
    with TGP and EPNG.(2)
    
    In December 2006, we paid a third
    party to assume our capacity obligations under this contract
    beginning November 1, 2007 through the contractual term of
    the contract which ends in 2015.  Other natural gas contracts.
 18




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##### Table of Contents



Power contracts.
  Markets
    and Competition
    
    Major oil and natural gas producers and their affiliates;
    Large domestic and foreign utility companies;
    Large local distribution companies and their affiliates;
    Other interstate and intrastate pipelines and their
    affiliates; and
    Independent energy marketers and power producers with varying
    scopes of operations and financial resources.  Power
    Segment
    El Paso







ExpirationOwnership


Gross




Year of PowerProject

Area


Interest


Capacity


Power Purchaser

Sales Contracts

Fuel Type(Percent)


(MW)BrazilManaus(1)


Brazil



100



238


Manaus Energia

2008

OilPorto
    Velho(2)


Brazil



50



404


Eletronorte

2010, 2023

OilRio
    Negro(1)


Brazil



100



158


Manaus Energia

2008

OilAsia & Central
    AmericaHabibullah


Pakistan



50



136


Pakistan Water and Power

2029

Natural GasSaba Power Co.


Pakistan



94



128


Pakistan Water and Power

2029

Residual Fuel OilKhulna Power Co.


Bangladesh



74



113


BPDB

2013

Heavy Fuel OilTipitapa


Nicaragua



60



51


Union Fenosa

2014

Heavy Fuel Oil     (1)
    
    Ownership of these plants will
    transfer to the power purchaser no later than January 2008.(2)
    
    The power purchaser has approached
    us with the opportunity to sell them our interest in the
    facility.    Regulatory
    Environment
  Pipelines.
 19




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##### Table of Contents




    rates and charges for natural gas transportation, storage, LNG
    terminalling and related services;
    certification and construction of new facilities;
    extension or abandonment of services and facilities;
    maintenance of accounts and records;
    relationships between pipelines and certain affiliates;
    terms and conditions of service;
    depreciation and amortization policies;
    acquisition and disposition of facilities; and
    initiation and discontinuation of services.    Exploration and Production.
    Power.
  Environmental
    Employees
   20




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##### Table of Contents



Executive
    Officers of the Registrant
    OfficerName

Office

Since

AgeDouglas L. Foshee

President and Chief Executive
    Officer of El Paso


2003



47D. Mark Leland

Executive Vice President and Chief
    Financial Officer of El Paso


2005



45Robert W. Baker

Executive Vice President and
    General Counsel of El Paso


2002



50Brent Smolik

Executive Vice President of
    El Paso and President of El Paso
    Exploration & Production Company


2006



45Susan B. Ortenstone

Senior Vice President (Human
    Resources and Administration) of El Paso


2003



50James C. Yardley

Executive Vice President of
    El Paso, Chairman of the Board of El Pasos
    Pipeline Group and Chairman of the Board and President of
    Southern Pipeline Group


2005



55James J. Cleary

President of Western Pipeline Group


2005



52Daniel B. Martin

Senior Vice President of Pipeline
    Operations


2005



50          21




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##### Table of Contents



Available
    Information
    ITEM 1A.
    RISK
    FACTORS  CAUTIONARY
    STATEMENT FOR PURPOSES OF THE SAFE HARBOR PROVISIONS
    OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF
    1995   22




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##### Table of Contents



Risks
    Related to Our Business
  Our
    operations are subject to operational hazards and uninsured
    risks.
      The
    success of our pipeline business depends, in part, on factors
    beyond our control.
    
    service area competition;
    expiration or turn back of significant contracts;
    changes in regulation and action of regulatory bodies;
    weather conditions that impact throughput and storage levels;
    price competition;
    drilling activity and 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 availability or popularity of other
    energy sources such as hydroelectric, nuclear, wind, and coal
    power and fuel oil;
    availability and cost of capital to fund ongoing maintenance and
    growth projects;
    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 prices in certain supply
    and demand areas.  The
    revenues of our pipeline businesses are generated under
    contracts that must be renegotiated periodically.
    
    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; 23




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##### Table of Contents




    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 natural gas
    supply points; and
    regulatory actions.  Fluctuations
    in energy commodity prices could adversely affect our pipeline
    businesses.
    
    regional, domestic and international supply and demand;
    availability and adequacy of transportation facilities;
    energy legislation;
    federal and state taxes, if any, on the sale or transportation
    of natural gas;
    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.
    
    our ability to obtain necessary approvals and permits by
    regulatory agencies on a timely basis and on terms that are
    acceptable to us;
    the ability to obtain continued access to sufficient capital to
    fund expansion projects;
    the availability of skilled labor, equipment, and materials to
    complete expansion projects;
    potential changes in federal, state and local statutes and
    regulations, including environmental requirements, that prevent
    a project from proceeding or increase the anticipated cost of
    the project;
    impediments on our ability to acquire
    rights-of-way
    or land rights on a timely basis or on terms that are acceptable
    to us;
    our 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; 24




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##### Table of Contents




    the lack of future growth; and
    the lack of transportation, storage or throughput commitments.    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.
    
    the level of consumer demand for, and the supply of, natural gas
    and oil;
    the availability and reliability of commodity processing,
    gathering and pipeline capacity;
    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;
    weather conditions, such as unusually warm or cold weather, and
    hurricanes in the Gulf of Mexico;
    market uncertainty;
    political conditions or hostilities in natural gas and oil
    producing regions;
    worldwide economic conditions; and
    changes in demand for the use of natural gas and oil because of
    market concerns about global warming or changes in governmental
    policies and regulations due to climate change initiatives.    The
    success of our exploration and production business is dependent,
    in part, on factors that are beyond our control.
    
    the results of future drilling activity;
    the availability and significant increases in future costs 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; 25




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##### Table of Contents




    our ability to expand our leased land positions in desirable
    areas, which often are subject to intensely competitive
    conditions from other companies
    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;
    governmental action affecting the profitability of our
    exploration and production activities, such as increased royalty
    rates payable on oil and gas leases, the imposition of
    additional taxes on such activities or the modification or
    withdrawal of tax incentives in favor of exploration and
    development activity;
    our lack of control over jointly owned properties and properties
    operated by others;
    declines in production volumes, including those from the Gulf of
    Mexico; and
    continued access to sufficient capital to fund drilling programs
    to develop and replace a reserve base with rapid depletion
    characteristics.  Our
    natural gas and oil drilling and producing operations involve
    many risks and may not be profitable.
        Estimating
    our reserves, production and future net cash flow is inherently
    imprecise.
   26




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##### Table of Contents



The
    success of our exploration and production business depends upon
    our ability to replace reserves that we produce.
    We
    face competition from third parties to acquire and develop
    natural gas and oil reserves.
    Our
    use of derivative financial instruments could result in
    financial losses.
  over-the-counter
   27




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##### Table of Contents



Our
    businesses are subject to the risk of payment defaults by our
    counterparties.
    Our
    foreign operations and investments involve special
    risks.
    
    loss of revenue, property and equipment as a result of hazards
    such as wars or insurrection;
    the effects of currency fluctuations and exchange controls, such
    as devaluation of foreign currencies and other economic problems;
    changes in laws, regulations and policies of foreign
    governments, including those associated with changes in the
    governing parties, nationalization, and expropriation; and
    protracted delays in securing government consents, permits,
    licenses, or other regulatory approvals necessary to conduct our
    operations.  Retained
    liabilities associated with businesses that we have sold could
    exceed our estimates and we could experience difficulties in
    managing these liabilities.
    Our
    business requires the retention and recruitment of a skilled
    workforce and the loss of employees could result in the failure
    to implement our business plans.
    Risks
    Related to Legal and Regulatory Matters
  The
    outcome of pending governmental investigations could be
    materially adverse to us.
   28




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##### Table of Contents



The
    agencies that regulate our pipeline businesses and their
    customers affect our profitability.
      Environmental
    compliance and remediation costs and the costs of environmental
    liabilities could exceed our estimates.
  clean-up
  
    estimating pollution control and clean up costs, including for
    sites where preliminary site investigation or assessments have
    been completed;
    discovering new sites or additional information at existing
    sites;
    quantifying liability under environmental laws that impose joint
    and several liability on all potentially responsible
    parties; and
    evaluating and understanding environmental laws and regulations,
    including their interpretation and enforcement.   29




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##### Table of Contents



Costs
    of litigation matters and other contingencies could exceed our
    estimates.
    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.
    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.
      We are
    subject to financing and interest rate risks.
    
    our credit ratings;
    the unhedged portion of our exposure to 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 hydrocarbon products. 30




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##### Table of Contents



ITEM 1B.
    UNRESOLVED
    STAFF COMMENTS    ITEM 2.
    PROPERTIES      ITEM 3.
    LEGAL
    PROCEEDINGS    Oscar S.
    Wyatt, Jr et al v. El Paso Corporation, William
    Wise, H. Brent Austin, Ralph Eads, Rodney D. Erskine, Ronald
    Kuehn, Jr., D. Dwight Scott, Credit Suisse First Boston LLC
    and PricewaterhouseCoopers LLP.
  Environmental
    Proceedings
  Natural Buttes.
  ITEM 4.
    SUBMISSION
    OF MATTERS TO A VOTE OF SECURITY HOLDERS   31




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##### Table of Contents



PART II  ITEM 5.
    MARKET
    FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS
    AND ISSUER PURCHASES OF EQUITY SECURITIES    Quarterly Stock Prices.
  High


Low


Dividends2006Fourth Quarter

$
15.84


$
12.92


$
0.04Third Quarter


16.39



12.82



0.04Second Quarter


16.00



11.85



0.04First Quarter


13.95



11.80



0.042005Fourth Quarter

$
14.07


$
10.78


$
0.04Third Quarter


14.16



11.13



0.04Second Quarter


11.87



9.30



0.04First Quarter


13.15



10.01



0.04   Stock Performance Graph.
 32




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##### Table of Contents



COMPARISON
    OF ANNUAL CUMULATIVE TOTAL RETURNS
  
  12/01


12/02


12/03


12/04


12/05


12/06El Paso
    Corporation


$
100



$
16.78



$
20.18



$
26.12



$
30.97



$
39.37S&P 500 Stock
    Index


$
100



$
77.90



$
100.25



$
111.15



$
116.61



$
135.03S&P 500 Oil & Gas
    Storage & Transportation
    Index(1)


$
100



$
23.68



$
38.62



$
54.04



$
71.38



$
85.07Peer Group


$
100



$
82.63



$
113.63



$
142.76



$
187.06



$
211.96   (1)
    
    The S&P 500 Oil & Gas
    Storage & Transportation Index was created as of
    May 1, 2005 and thus, historical values for this index were
    not available. Accordingly, we provided this comparison against
    a custom index which includes the companies in the
    Standard & Poors 500 Oil & Gas
    Storage & Transportation Index, including El Paso.(2)
    
    The annual values of each
    investment are based on the share price appreciation and assume
    cash dividend reinvestment. The calculations exclude any
    applicable brokerage commissions and taxes. Cumulative total
    stockholder returns from each investment can be calculated from
    the annual values given above.  Dividends Declared.
  Other.
  Odd-lot Sales Program. 1-877-453-1503.
 33




---



##### Table of Contents



ITEM 6: SELECTED
    FINANCIAL DATA  Form 10-K.
  As of or for the Year Ended December 31,2006


2005


2004


2003


2002(In millions, except per common share amounts)Operating Results Data:Operating revenues

$
4,281


$
3,359


$
4,783


$
5,596


$
5,909Income(loss) from continuing
    operations

$
531


$
(506
)

$
(1,032
)

$
(795
)

$
(1,531
)Net income(loss) available to
    common stockholders

$
438


$
(633
)

$
(947
)

$
(1,883
)

$
(1,875
)Basic earnings (loss) per common
    share from continuing operations

$
0.73


$
(0.82
)

$
(1.61
)

$
(1.33
)

$
(2.74
)Diluted earnings (loss) per common
    share from continuing operations

$
0.72


$
(0.82
)

$
(1.61
)

$
(1.33
)

$
(2.74
)Cash dividends declared per common
    share

$
0.16


$
0.16


$
0.16


$
0.16


$
0.87Basic average common shares
    outstanding


678



646



639



597



560Diluted average common shares
    outstanding


739



646



639



597



560Financial Position Data:Total assets

$
27,261


$
31,840


$
31,383


$
36,968


$
41,947Long-term financing obligations,
    less current maturities


13,329



16,282



17,506



19,193



15,594Securities of subsidiaries


31



31



367



447



3,421Stockholders equity


4,186



3,389



3,438



4,346



5,749    34




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##### Table of Contents



ITEM 7.
    MANAGEMENTS
    DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
    OPERATIONS  Overview
    Our Business
  Results of Operations year-over-year
  Capital Resources and Liquidity
  Off Balance Sheet Arrangements, Contractual Obligations, and
    Commodity-Based Derivative Contracts
  Critical Accounting Estimates and/or
  Our
    Business
  Primary Business Purpose and Description.
  Drivers of our Profitability.
    
    Expanding our existing pipeline systems to meet demand growth
    and gain access to new supply areas and sources;
    Contracting and recontracting pipeline capacity with our
    customers;
    Maintaining approval by FERC of acceptable rates and terms of
    service, including successfully resolving rate cases; and
    Improving operating efficiency. 35




---



##### Table of Contents




    Increasing our natural gas and oil proved reserve base and
    production volumes through successful drilling programs or
    acquisitions; and
    Finding and producing natural gas and oil at a reasonable cost.    Summary of Overall Performance in 2006.
  Area of Operations

Significant HighlightsPipelines

Announced the sale of ANR, our
    Michigan storage assets and our 50 percent interest in
    Great Lakes Gas TransmissionImplemented a FERC approved  rate
    case settlement  for Colorado Interstate Gas Company and filed a
    rate case settlement for approval with the FERC for El Paso
    Natural Gas CompanyRe-contracted or contracted
    available or expiring capacityCompleted several expansion
    projects and proceeded with other expansion projects in our
    pipeline systems and at our Elba Island LNG facilityRepaired significant damage to
    sections of our Gulf Coast and offshore pipeline facilities
    caused by Hurricanes Katrina and RitaE & P

Increased production volumes in
    each quarter of the year despite lower than planned annual
    production as a result of delays in bringing certain production
    online, delays in recovering lost volumes due to Hurricanes
    Katrina and Rita and higher than planned maintenance in certain
    onshore fieldsEntered into additional derivative
    contracts in 2006 to manage price risk on a substantial portion
    of our 2007 natural gas productionReplaced our production primarily
    through our capital drilling program, achieving an overall
    drilling success rate of 98 percentMarketing

Entered into agreements to assign,
    terminate or divest of a significant transportation contract and
    certain of our historical natural gas and power contractsOther

Resolved various legal and
    contractual disputes, including a settlement of the pending
    shareholder and derivative actions, those related to our
    Brazilian power plants and other domestic legal mattersDivested of a majority of our
    remaining power operations for total proceeds of approximately
    $0.9 billion, including our Macae power facility   What to Expect Going Forward.
 36




---



##### Table of Contents



Update of Credit Metrics.
  
    Reducing debt by $2.8 billion, primarily through asset
    sales and issuing common stock;
    Restructuring our revolving credit facilities with improved
    terms;
    Receiving upgraded senior unsecured debt ratings to B2 with a
    positive outlook from Moodys and B with a positive outlook
    from Standard and Poors; and
    Entering into contracts to eliminate the price risk on a portion
    of our historical Marketing natural gas book.    Results
    of Operations
  Overview
     37




---



##### Table of Contents



2006


2005


2004(In millions)SegmentPipelines

$
1,187


$
924


$
1,059Exploration and Production


640



696



734Marketing


(71
)


(837
)


(539
)Power


82



(89
)


(747
)Field Services






285



84Segment EBIT


1,838



979



591Corporate and other


(88
)


(521
)


(217
)Consolidated EBIT


1,750



458



374Interest and debt expense


(1,228
)


(1,286
)


(1,497
)Distributions on preferred
    interests of consolidated subsidiaries






(9
)


(25
)Income taxes


9



331



116Income (loss) from continuing
    operations


531



(506
)


(1,032
)Discontinued operations, net of
    income taxes


(56
)


(96
)


85Cumulative effect of accounting
    changes, net of income taxes






(4
)


Net income (loss)

$
475


$
(606
)

$
(947
)     Pipelines
    Segment
  Overview
    % of TotalType

Description

RevenuesReservation

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.


79Usage and Other

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. We also
    earn revenues from the processing and sale of natural gas
    liquids and other miscellaneous sources.


21  38




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##### Table of Contents



Percent of TotalBBtu/d


Available Capacity2007


3,450



152008


2,628



112009


1,764



82010


3,339



142011


2,171



92012 and beyond


10,056



43   Summary
    of Operational and Financial Performance
     39




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##### Table of Contents



Operating
    Results
  2006


2005


2004(In millions, except volumeamounts)Operating revenues

$
2,402


$
2,171


$
2,145Operating expenses


(1,339
)


(1,392
)


(1,218
)Operating income


1,063



779



927Other income


124



145



132EBIT

$
1,187


$
924


$
1,059Throughput volumes
    (BBtu/d)(1)TGP


4,584



4,493



4,519EPNG and MPC


4,255



4,214



4,235CIG, WIC and CPG


4,301



3,734



2,808SNG


2,167



1,984



2,163Equity investments


1,705



1,645



1,698Total throughput


17,012



16,070



15,423     (1)
    
    Volumes exclude intrasegment
    activities.    2006 to 2005


2005 to 2004Variance


VarianceRevenue


Expense


Other


EBIT


Revenue


Expense


Other


EBITImpact


Impact


Impact


Impact


Impact


Impact


Impact


ImpactFavorable/(Unfavorable)(In millions)Higher reservation and services
    revenues

$
128


$



$



$
128


$
24


$



$



$
24Gas not used in operations,
    revaluations, processing revenues and other natural gas sales


20



38







58



(45
)


8







(37
)Expansions


75



(9
)


(10
)


56



75



(28
)


(2
)


45Hurricanes Katrina and Rita






(1
)






(1
)


(13
)


(28
)






(41
)Impairment of pipeline development
    projects






30







30







(46
)






(46
)General and administrative expense






52







52







(42
)






(42
)Higher depreciation expense






(19
)






(19
)






(2
)






(2
)Higher pipeline integrity expense






(19
)






(19
)














Operating costs






(13
)






(13
)






(34
)






(34
)Enron bankruptcy settlement


15



3







18















Sale of interest in gathering
    system










(11
)


(11
)














Other(1)


(7
)


(9
)






(16
)


(15
)


(2
)


15



(2
)Total impact on EBIT

$
231


$
53


$
(21
)

$
263


$
26


$
(174
)

$
13


$
(135
)     (1)
    
    Consists of individually
    insignificant items on several of our pipeline systems. 40




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##### Table of Contents



Higher Reservation and Other Services
    Revenues.
  Gas Not Used in Operations, Revaluations, Processing Revenues
    and Other Natural Gas Sales.
  Expansions.
  Projects Placed in Service.
  Projects
    Not Yet Completed.
  Anticipated Completion

EstimatedProject

or In-Service Date

Cost


Estimated Future RevenuesLouisiana Deepwater Link

July 2007

$
55 million
(1)

(2)Triple-T Extension

September 2007

$
33 million
(3)

(2)Essex Middlesex Project

November 2007

$
47 million


$1 million in 2007
    $8 million annually thereafterNortheast
    ConneXion  New England

November 2007

$
103 million


$6 million in 2007$37 million annually thereafterCypress
    Expansion(4)

May 2007

$
321 million


$62 million annually     (1)
    
    Estimate reflects anticipated
    payment of approximately $15 million in contributions to a
    third party.(2)
    
    Revenues for these projects will be
    based on throughput levels as natural gas reserves are developed.(3)
    
    Amount shown is net of anticipated
    the receipt of approximately $12 million in
    contributions-in-aid-of
    construction.(4)
    
    Project will consist of three
    phases. The anticipated completion date is related to
    phase 1.  Hurricanes Katrina and Rita.
  Impairment of Pipeline Development
    Projects.
  General and Administrative Expenses.
 41




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##### Table of Contents



Higher Depreciation Expense.
  Pipeline Integrity Costs.
  Operating Costs.
  Enron Bankruptcy Settlement.
  Regulatory Matters/Rate Cases.
  
    EPNG  EPNG negotiated a settlement of its rate case
    that was filed with the FERC in December 2006. The settlement
    provides benefits for both EPNG and its customers for a
    three-year period ending December 31, 2008. For a further
    discussion of this settlement, see Item 8, Financial
    Statements and Supplementary Data, Note 13.
    CIG  In August 2006, the FERC approved a settlement
    reached with CIGs customers effective October 1,
    2006. The settlement establishes system-wide base rates through
    at least September 2010, but no later than September 2011, and
    establishes a sharing mechanism to encourage additional fuel
    savings. We anticipate an increase in revenues of approximately
    $6 million annually from the effective date of the
    settlement.  
    MPC  MPC is required by its previous rate case
    settlement to file for new rates to be effective in
    March 2007. We anticipate a rate decrease resulting from a
    variety of factors, including a decline in the rate base and
    various changes in rate design since the last rate case although
    the amount of the impact is not yet determinable. 42




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##### Table of Contents



Exploration
    and Production Segment
  Overview
    and Strategy
      
    Re-shaping our portfolio to provide greater optionality for
    achieving our long term performance goals;  
    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 our
    current drilling inventory.    Significant
    Operational Factors Affecting the Year Ended December 31,
    2006
  Production.
  2006


2005


2004United StatesOnshore


345



300



231Texas Gulf
    Coast(1)


187



211



283Gulf of Mexico Shelf / south
    Louisiana


174



179



276InternationalBrazil(2)


24



53



24Total Consolidated


730



743



814Four Star
    (3)


68



24



     (1)
    
    During 2006, we completed the sale
    of certain non-strategic south Texas properties with production
    of approximately 5 MMcfe/d. In January 2007, we acquired
    certain properties with net production on the acquisition date
    of approximately 12 MMcfe/d. (2)
    
    Production volumes decreased due to
    a contractual reduction of our ownership interest in the
    Pescada-Arabaiana Field in 2006. (3)
    
    Amounts represent our proportionate
    share of the production of Four Star which was acquired in the
    third quarter of 2005. 43




---



##### Table of Contents



2006
    Drilling Results
  Onshore.
  Texas Gulf Coast.
  Gulf of Mexico Shelf and south Louisiana.
  Brazil.
  Egypt.
  Cash Operating Costs.
 44




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##### Table of Contents



Reserve Replacement Costs / Reserve Replacement
    Ratio.
  Reserve replacement ratio

Sum of reserve
    additions(1)Actual production for the
    corresponding period   Reserve replacement cost / Mcfe

Total oil and gas capital
    costs(2)Sum of reserve additions
    (1)     (1)
    
    Reserve additions include proved
    reserves and reflect reserve revisions, extensions, discoveries,
    and other additions and acquisitions and do not include unproved
    reserve quantities or proved reserve additions attributable to
    investments accounted for using the equity method. Amounts are
    derived directly from the table presented inItem 8, Financial Statements
    and Supplementary Data, Supplemental Natural Gas and Oil
    Operations.  (2)
    
    Total oil and gas capital costs
    include the costs of development, exploration, and property
    acquisition activities conducted to add reserves and exclude
    asset retirement obligations. Amounts are derived directly from
    the table presented in Item 8, Financial Statements and
    Supplementary Data, Supplemental Natural Gas and Oil Operations.        2006


2005


2004($ / Mcfe)Reserve replacement costs,
    including acquisitions

$
4.17


$
2.75


$
21.85Reserve replacement costs,
    excluding acquisitions


4.19



3.19



N/A(1
) (% of Production)Reserve replacement ratio,
    including acquisitions


108
%


195
%


11
%Reserve replacement ratio,
    excluding acquisitions


107



93



(10
)     (1)
    
    Not meaningful in 2004 due to
    downward revisions in previous estimates of reserves. 45




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##### Table of Contents



Capital Expenditures.
  2006


2005


2004Total oil and gas capital
    costs(1)

$
1,193


$
1,462


$
743Less: acquisition capital


(4
)


(651
)


(102
)Capital expenditures, excluding
    acquisitions

$
1,189


$
811


$
641     (1)
    
    Total oil and gas capital costs
    include the costs of development, exploration and property
    acquisition activities conducted to add reserves and exclude
    asset retirement obligations. Amounts are derived directly from
    the table presented in Item 8, Financial Statements and
    Supplementary Data, Supplemental Natural Gas and Oil Operations.  Outlook
    for 2007
    
    Average daily production volumes for the year of approximately
    740 MMcfe/d to 795 MMcfe/d, which excludes
    approximately 60 MMcfe/d to 65 MMcfe/d from our equity
    investment in Four Star. Our goal is to achieve between three
    and eight percent average annual production growth over the next
    several years.  
    Capital expenditures, excluding acquisitions, between
    $1.4 billion and $1.5 billion, which represents a
    20 percent increase over 2006. While 85% of the
    companys planned 2007 capital program is allocated to its
    domestic program, we plan to spend $215 million in
    international capital in 2007, primarily in our Brazil
    exploration and development program. In January 2007, we
    acquired producing properties and undeveloped acreage in Zapata
    County, Texas for $249 million which complement our
    existing Texas Gulf Coast operations and provide a re-entry into
    the Lobo trend. The assets acquired had net production of
    approximately 12 MMcfe/d on the acquisition date. Estimated
    proved reserves were approximately 84 Bcfe of which
    approximately 73 percent was undeveloped.  
    Average cash operating costs which include production costs,
    general and administrative expenses and other expenses of
    approximately $1.68/Mcfe to $2.00/Mcfe for the year; and  
    Depreciation, depletion, and amortization rate of between
    $2.50/Mcfe and $2.75/Mcfe in the first quarter of 2007 compared
    with $2.58/Mcfe in the fourth quarter of 2006. 46




---



##### Table of Contents



Price
    Risk Management Activities
    Fixed Price














BasisSwaps(1)


Floors(1)


Ceilings(1)


Swaps(1)(2)Volumes


Price


Volumes


Price


Volumes


Price


VolumesNatural Gas2007


78


$
7.70



55


$
8.00



55


$
16.89



1102008


5


$
3.42



















2009


5


$
3.56



















2010-2012


11


$
3.81



















Oil2007


192


$
35.15



















     (1)
    
    Volumes presented are TBtu for
    natural gas and MBbl for oil. Prices presented are per MMBtu of
    natural gas and per Bbl of oil.(2)
    
    Our basis swaps effectively
    lock-in locational price differences on a portion of
    our natural gas production in Texas and Oklahoma.     47




---



##### Table of Contents



Operating
    Results and Variance Analysis
    2006


2005


2004(In millions, except forvolumes and prices)Operating Revenues:Natural gas

$
1,406


$
1,420


$
1,428Oil, condensate and NGL


430



371



305Other


18



(4
)


2Total operating revenues


1,854



1,787



1,735Operating Expenses:Depreciation, depletion and
    amortization


(645
)


(612
)


(548
)Production
    costs(1)


(331
)


(261
)


(210
)Cost of products and services


(87
)


(47
)


(54
)General and administrative expenses


(156
)


(185
)


(173
)Other


(10
)


(11
)


(24
)Total operating expenses


(1,229
)


(1,116
)


(1,009
)Operating Income


625



671



726Other
    Income(2)


15



25



8EBIT

$
640


$
696


$
734   48




---



##### Table of Contents



Percent





Percent2006


Variance


2005


Variance


2004Consolidated volumes, prices
    and costs per unit:Natural gasVolumes (MMcf)


220,402



(1
)%


222,292



(9
)%


244,857Prices
    ($/cf)(3)Average realized prices including
    hedges

$
6.38




%

$
6.39



10
%

$
5.83Average realized prices excluding
    hedges

$
6.64



(12
)%

$
7.53



28
%

$
5.90Average transportation costs
    ($/Mcf)

$
0.23



28
%

$
0.18



6
%

$
0.17Oil, condensate and NGLVolumes (MBbls)


7,686



(6
)%


8,136



(8
)%


8,818Prices
    ($/Bbl)(3)Average realized prices including
    hedges

$
55.90



23
%

$
45.60



32
%

$
34.61Average realized prices excluding
    hedges

$
56.21



21
%

$
46.43



34
%

$
34.75Average transportation costs
    ($/Bbl)

$
0.82



30
%

$
0.63



(44
)%

$
1.12Total equivalent volumesMMcfe


266,518



(2
)%


271,107



(9
)%


297,766MMcfe/d


730



(2
)%


743



(9
)%


814Production costs and other cash
    operating costs ($/Mcfe)Average lease operating cost

$
0.95



32
%

$
0.72



20
%

$
0.60Average production taxes


0.29



21
%


0.24



118
%


0.11Total production
    cost(1)

$
1.24



29
%

$
0.96



35
%

$
0.71Average general and administrative
    cost

$
0.59



(13
)%

$
0.68



17
%

$
0.58Average taxes, other than
    production and income taxes

$
0.03




%

$
0.03




%

$
Total cash operating
    costs(4)

$
1.86



11
%

$
1.67



29
%

$
1.29Unit of production depletion cost
    ($/Mcfe)

$
2.29



9
%

$
2.10



24
%

$
1.69Unconsolidated affiliate
    volumes (Four
    Star)(2)Natural gas (MMcf)


18,140







6,689Oil, condensate and NGL (MBbls)


1,087







359Total equivalent volumesMMcfe


24,663







8,844MMcfe/d


68







24     (1)
    
    Production costs include lease
    operating costs and production related taxes (including ad
    valorem and severance taxes).(2)
    
    Includes equity earnings from our
    investment or our proportionate share of volumes in Four Star
    acquired in the third quarter 2005.(3)
    
    Prices are stated before
    transportation costs.(4)
    
    See further discussion on page 44. 49




---



##### Table of Contents



Year
    Ended December 31, 2006 Compared to Year Ended
    December 31, 2005
    VarianceOperating


OperatingRevenue


Expense


Other


EBITFavorable/(Unfavorable)(In millions)Natural Gas RevenueLower realized prices in 2006

$
(197
)

$



$



$
(197
)Impact of hedges


197











197Lower production volumes in 2006


(14
)










(14
)Oil, Condensate and NGL
    RevenueHigher realized prices in 2006


75











75Impact of hedges


5











5Lower volumes in 2006


(21
)










(21
)Depreciation, Depletion and
    Amortization ExpenseHigher depletion rate in 2006






(51
)






(51
)Lower production volumes in 2006






10







10Production CostsHigher lease operating costs in
    2006






(58
)






(58
)Higher production taxes in 2006






(12
)






(12
)General and Administrative
    Expenses






29







29OtherChange in fair value of oil and
    basis swaps


(31
)










(31
)Earnings from investment in Four
    Star










(9
)


(9
)Processing plants


41



(29
)






12Other


12



(2
)


(1
)


9Total Variances

$
67


$
(113
)

$
(10
)

$
(56
)   Operating revenues.
    Depreciation, depletion and amortization
    expense.
  Production costs.
 50




---



##### Table of Contents



General and administrative expenses.
  Other.
 51




---



##### Table of Contents



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


OperatingRevenue


Expense


Other


EBITFavorable/(Unfavorable)(In millions)Natural Gas RevenueHigher realized prices in 2005

$
362


$



$



$
362Lower volumes in 2005


(133
)










(133
)Impact of hedges


(237
)










(237
)Oil, Condensate and NGL
    RevenueHigher realized prices in 2005


95











95Lower volumes in 2005


(24
)










(24
)Impact of hedges


(5
)










(5
)Depreciation, Depletion and
    Amortization ExpenseHigher depletion rate in 2005






(110
)






(110
)Lower production volumes in 2005






45







45Production
    CostsHigher lease operating costs in
    2005






(17
)






(17
)Higher production taxes in 2005






(34
)






(34
)General and Administrative
    Expenses






(12
)






(12
)OtherEarnings from investment in Four
    Star










19



19Other


(6
)


21



(2
)


13Total Variances

$
52


$
(107
)

$
17


$
(38
)   Operating revenues.
  Depreciation, depletion and amortization
    expense.
  Production costs.
  General and administrative expenses.
 52




---



##### Table of Contents



Marketing
    Segment
    ExpectedEarningsContract Type

Description

Significant Events/Remaining Exposure

VolatilityMark-to-MarketProduction-related natural gas and
    oil derivatives

Option contracts with various
    floor and ceiling prices

Terminated our 2007 natural gas
    collars and replaced them with natural gas puts in November
    2006. Our collars significantly impacted our results in 2006 due
    to changes in natural gas prices and our new puts may have an
    impact in the future if volatility continues.

HighPower contracts

Pennsylvania-New Jersey-Maryland
    (PJM) basis and installed capacity positions.

Impacted by changes in regional
    power prices in 2006 and may have an impact in the future if
    volatility continues.

ModeratePJM commodity contracts.

Remaining commodity positions are
    hedged at PJM west hub.

LowOther natural gas contracts

Fixed-price, physical delivery
    contracts; fixed-for-float swaps.

Sold, terminated or entered into
    offsetting derivative transactions in 2006 to substantially
    eliminate the price risk associated with a significant number of
    contracts, which reduces our future earnings exposure to changes
    in natural gas prices.

LowAccrualTransportation-related natural gas
    contracts

Pipeline capacity contracts.

Released or assigned capacity
    related to Alliance, TGP and a pipeline serving California,
    which should significantly reduce our exposure to future losses.

LowLong-term gas supply obligations

Primarily ten contracts with
    delivery obligations up to 0.7 Bcf/d with expiration dates
    ranging from 2008 to 2028.

The majority of our supply
    contracts are index-priced.

Low  53




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##### Table of Contents



Operating
    Results
  Overview. year-to-year
  2006


2005


2004(In millions)Gross Margin by Significant
    Contract Type:Production-Related Natural Gas
    and Oil ContractsChanges in fair value of options
    and swaps

$
269


$
(436
)

$
53Changes in fair value of other
    production-related derivatives










(439
)Gross margin


269



(436
)


(386
)Contracts Related to Historical
    Trading Operations:Natural gas transportation-related
    natural gas contracts:Demand charges


(125
)


(156
)


(151
)Settlements and termination
    payments(1)


(110
)


121



87Changes in fair value of other
    natural gas derivative
    contracts(2)


(163
)


39



44Changes in fair value of power
    contracts


71



(386
)


(121
)Other






22



19Gross
    margin(3)


(327
)


(360
)


(122
)Total gross margin


(58
)


(796
)


(508
)Operating
    expenses(4)


(33
)


(59
)


(54
)Operating loss


(91
)


(855
)


(562
)Other income, net


20



18



23EBIT

$
(71
)

$
(837
)

$
(539
)     (1)
    
    Amount for 2006 includes a
    $188 million loss in operating revenues related to Alliance
    further discussed below and a $50 million gain in 2004
    related to early termination of an LNG contract.  (2)
    
    Amounts for 2006 include the loss
    on our MCV contract described above.  (3)
    
    Gross margin consists of revenues
    from commodity trading and origination activities less costs of
    commodities sold, including changes in the fair value of
    derivative contracts.  (4)
    
    In 2006 and 2005, we incurred lower
    corporate overhead allocation and general and administrative
    expenses based on overall cost reduction efforts at the
    corporate level and our reduced level of operations. In 2005, we
    recorded $19 million of legal settlements and reserves,
    which resulted in increased operating expenses during 2005.  Production-related
    Natural Gas and Oil Derivatives
  Options and swaps.
 54




---



##### Table of Contents



period-to-period marked-to-market
  Floors(1)


Ceilings(1)Average





AverageVolumes


Price


Volumes


PriceNatural Gas2007


89


$
7.50






$
2008


18


$
6.00



18


$
10.002009


17


$
6.00



17


$
8.75Oil2007


1,009


$
55.00



1,009


$
60.382008


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.      Other production-related derivatives.
  Contracts
    Related to Historical Trading Operations
  Natural gas transportation-related
    contracts.
 55




---



##### Table of Contents



2006


2005


2004Alliance:Demand
    charges(1)

$
64


$
65


$
61Recovery


59
%


93
%


72
%Enterprise Texas:Demand charges

$
12


$
26


$
27Recovery



%(2)


8
%


2
%Other:Demand
    charges(3)

$
49


$
65


$
63Recovery


92
%


94
%


38
%     (1)
    
    In 2006, excluded from this amount
    is the $188 million we paid in conjunction with the sale of
    this contract described above. (2)
    
    In 2006, we were unable to recover
    demand charges and incurred $4 million of losses in excess
    of the demand charges related to managing the capacity under
    these contracts. (3)
    
    Includes demand charges related to
    storage contracts of $1 million, $1 million and
    $2 million in 2006, 2005, and 2004.  Other natural gas derivative contracts.
  mark-to-market mark-to-market
  Power Contracts.
    Other.
 56




---



##### Table of Contents



Power
    Segment
  Overview.
    2006


2005


2004(In millions)EBIT by Area:BrazilImpairment of Manaus and Rio Negro

$



$



$
(183
)EBIT from operations


64



55



64Other International
    PowerImpairments related to anticipated
    sales


(13
)


(176
)


(182
)Gain on sale of KIECO, PPN and
    Chinese plants


1



131



EBIT from
    operations(1)


(1
)


34



64Domestic PowerImpairments, net of gains (losses)
    on sales


10



(167
)


(590
)Favorable resolution of bankruptcy
    claim






53



EBIT from operations










133Gain on sale of
    available-for-sale
    investment(2)


47



40



Other(3)


(26
)


(59
)


(53
)EBIT

$
82


$
(89
)

$
(747
)     (1)
    
    EBIT from operations includes a
    $17 million dividend on investment fund recorded in 2005.(2)
    
    With the disposition of our shares
    in 2005 and 2006, we no longer have an interest in International
    Commodity Exchange.(3)
    
    Other consists of indirect expenses
    and general and administrative costs. Also includes impairments
    and losses on the sales of power turbines of $27 million
    and $1 million recorded in 2005 and 2004.  Brazil.
  Bolivia-to-Brazil Argentina-to-Chile
 57




---



##### Table of Contents



Bolivia-to-Brazil Argentina-to-Chile
  Other International Power.
  Domestic Power.
 58




---



##### Table of Contents



Field
    Services Segment
    2005


2004(In millions)Gathering and processing gross
    margins(1)

$
25


$
93Operating expensesLoss on long-lived assets


(10
)


(507
)Other operating expenses


(31
)


(87
)Operating loss


(16
)


(501
)Earnings from unconsolidated
    affiliates


301



618Other expense






(33
)EBIT

$
285


$
84   2005


2004(In millions)Gathering and Processing
    ActivitiesGathering and processing margins

$
25


$
93Operating expenses


(8
)


(87
)Other income


7



11EBIT


24



17GulfTerra/Enterprise-related
    ItemsAssets/interests sold to Gulf
    Terra and EnterpriseSale of GP/LP interests


183



507Goodwill impairment






(480
)Other


4



(47
)Equity earnings






100EBIT


187



80Other Asset SalesSale of Javelina investment


111



Other


(37
)


(13
)74



(13
)EBIT

$
285


$
84     (1)
    
    Gross margins consist of operating
    revenues less cost of products sold. We believe that this
    measurement is more meaningful for understanding and analyzing
    our Field Services segments operating results in 2005 and
    2004 because commodity costs historically were a significant
    factor in the determination of profit from our midstream
    activities.  Gathering and Processing Activities.
 59




---



##### Table of Contents



GulfTerra/Enterprise Related Items.
  
    Gain of $507 million upon the sale of our remaining
    50 percent interest in the general partner of GulfTerra to
    Enterprise in 2004. As a result of this sale, we also impaired
    goodwill recorded on the segment; and
    Gain of $183 million on the sale of our remaining general
    partner and limited partner interests in Enterprise in 2005.  Corporate
    and Other Expenses, Net
    2006


2005


2004(In millions)Change in litigation, insurance
    and other reserves

$
(65
)

$
(418
)

$
(81
)Western Energy Settlement






(72
)


(38
)Restructuring charges






(27
)


(91
)Debt related gains (losses):Foreign currency fluctuations on
    Euro-denominated debt


(20
)


36



(26
)Early extinguishment/exchange of
    debt


(26
)


(29
)


(18
)Other


23



(11
)


37Total EBIT

$
(88
)

$
(521
)

$
(217
)   Litigation, Insurance, and Other Reserves.
  Restructuring Charges.
 60




---



##### Table of Contents



Interest
    and Debt Expense
  Years Ended December 31,2006


2005


2004(In millions)Long-term debt, including current
    maturities

$
1,193


$
1,249


$
1,419Other interest


35



37



78Total interest and debt expense

$
1,228


$
1,286


$
1,497     Income
    Taxes
  Years Ended December 31,2006


2005


2004(In millions)Income taxes from continuing
    operations

$
(9
)

$
(331
)

$
(116
)Effective tax rate


(2
)%


40
%


10
%   1998-2000
      Discontinued
    Operations
       61




---



##### Table of Contents



Commitments
    and Contingencies
    Capital
    Resources and Liquidity
  Debt Obligations.
  Available Liquidity.
  Available cash

$
0.4Available capacity under our
    credit agreements


1.0Net available liquidity at
    December 31, 2006

$
1.4     Expected 2007 Cash Flows.
  Exploration andPipelines


Production(1)


TotalMaintenance

$
0.4


$
1.2


$
1.6Growth


0.6



0.5



1.1$
1.0


$
1.7


$
2.7     (1)
    
    Includes approximately
    $250 million spent in January 2007 for the acquisition of
    natural gas and oil properties.    Significant
    Factors That Could Impact Our Liquidity.
  Cash Margining Requirements on Derivative
    Contracts.
 62




---



##### Table of Contents



Hurricanes.
  Recoverable


UnrecoverableCosts


Costs(1)


TotalCumulative costs through 2006

$
190


$
265


$
455Estimated remaining costs


75



95



170Total costs


265


$
360


$
625Less: Reimbursements to date


(55
)Expected future reimbursements

$
210     (1)
    
    Includes capital expenditures of
    approximately $275 million.    Price Risk Management Activities.
 63




---



##### Table of Contents



Fixed Price














BasisSwaps(1)


Floors(1)


Ceilings(1)


Swaps(1)(2)Volumes


Price


Volumes


Price


Volumes


Price


VolumesNatural Gas2007


78


$
7.70



144


$
7.69



55


$
16.89



1102008


5


$
3.42



18


$
6.00



18


$
10.00



2009


5


$
3.56



17


$
6.00



17


$
8.75



2010-2012


11


$
3.81



















Oil2007


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.(2)
    
    Our basis swaps effectively
    lock-in locational price differences on a portion of
    our natural gas production in Texas and Oklahoma. 64




---



##### Table of Contents



Overview
    of Cash Flow Activities for 2006 Compared to 2005
  Years Ended December 31,2006


2005(In billions)Cash Flow from
    OperationsContinuing operating
    activitiesNet income (loss) before
    discontinued operations

$
0.5


$
(0.5
)Non-cash income adjustments


1.1



1.1Change in broker margin and other
    deposits


0.9



(0.7
)Change in other assets and
    liabilities


(0.7
)


0.1Total cash flow from operations

$
1.8


$
Other Cash InflowsContinuing investing
    activitiesNet proceeds from the sale of
    assets and investments

$
0.7


$
1.4Other


0.2



0.20.9



1.6Continuing financing
    activitiesNet proceeds from the issuance of
    long-term debt


0.4



1.6Proceeds from issuance of common
    and preferred stock


0.5



0.7Contribution from discontinued
    operations(1)


0.2



0.71.1



3.0Total other cash inflows

$
2.0


$
4.6Cash OutflowsContinuing investing
    activitiesCapital expenditures

$
2.2


$
1.6Net cash paid for acquisition






1.02.2



2.6Continuing financing
    activitiesPayments to retire long-term debt
    and redeem preferred interests


3.0



1.5Redemption of preferred stock of a
    subsidiary






0.3Dividends and other


0.2



0.23.2



2.0Total other cash outflows

$
5.4


$
4.6Net change in cash

$
(1.6
)

$
     (1)
    
    Amounts contributed from
    discontinued operations above are net of approximately
    $0.2 billion of debt repayments associated with the Macae
    power facility.   65




---



##### Table of Contents



Off-Balance
    Sheet Arrangements
    Guarantees
        Letters
    of Credit
    Interests
    in Variable Interest Entities
   66




---



##### Table of Contents



Contractual
    Obligations
    Due in Less


Due in 1 to


Due in 4 tothan 1 Year


3 Years


5 Years


Thereafter


Total(In millions)Long-term financing obligations:Principal

$
1,360


$
2,225


$
2,559


$
8,616


$
14,760Interest


1,090



1,997



1,608



9,035



13,730Liabilities from commodity-based
    derivative contracts


278



435



263



226



1,202Other contractual liabilities


70



44



27



35



176Operating leases


66



17



4



11



98Other contractual commitments and
    purchase obligations:Transportation and storage


98



81



68



153



400Other


424



66



24



26



540Total contractual obligations

$
3,386


$
4,865


$
4,553


$
18,102


$
30,906   Long Term Financing Obligations (Principal and
    Interest).
  Liabilities from Commodity-Based Derivative
    Contracts.
  Other Contractual Liabilities.
  Operating Leases.
 67




---



##### Table of Contents



Other Contractual Commitments and Purchase
    Obligations.
  
    Transportation and Storage
    Commitments.  Included in these amounts are
    commitments for demand charges for firm access to natural gas
    transportation and storage capacity.  
    Other Commitments.  Included in these amounts
    are 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. We have excluded asset retirement obligations
    and reserves for litigation, environmental remediation and
    self-insurance claims as liabilities are not contractually fixed
    as to timing and amount. We have excluded from these amounts
    contractual commitments of $223 million related to ANR
    which is reported in discontinued operations.  Commodity-Based Derivative Contracts.
  Maturity


Maturity


Maturity


Maturity


Maturity


TotalLess Than


1 to 3


4 to 5


6 to 10


Beyond


Fair1 Year


Years


Years


Years


10 Years


Value(In millions)Derivatives designated as
    hedges(1)Assets

$
144


$



$



$



$



$
144Liabilities


(17
)


(36
)


(25
)


(5
)






(83
)Total derivatives designated as
    hedges


127



(36
)


(25
)


(5
)






61Other commodity-based derivativesExchange-traded
    positions(1)Assets


128



208



17











353Non-exchange traded positionsAssets


162



66



40



34



8



310Liabilities


(261
)


(399
)


(238
)


(215
)


(6
)


(1,119
)Total other commodity-based
    derivatives


29



(125
)


(181
)


(181
)


2



(456
)Total commodity-based derivatives

$
156


$
(161
)

$
(206
)

$
(186
)

$
2


$
(395
)     (1)
    
    These positions are traded on
    active exchanges such as the New York Mercantile Exchange, the
    International Petroleum Exchange and the London Clearinghouse. 68




---



##### Table of Contents



Other


TotalDerivatives


Commodity-


Commodity-Designated


Based


Basedas Hedges


Derivatives


Derivatives(In millions)Fair value of contracts
    outstanding at December 31, 2004

$
(536
)

$
604


$
68Fair value of contract settlements
    during the
    period(1)


665



(174
)


491Change in fair value of contracts


(793
)


(767
)


(1,560
)Assignment of contracts






(442
)


(442
)Reclassification of derivatives
    that no longer qualify as hedges


11



(11
)


Option premiums
    paid(2)






27



27Net change in contracts
    outstanding during the period


(117
)


(1,367
)


(1,484
)Fair value of contracts
    outstanding at December 31, 2005


(653
)


(763
)


(1,416
)Fair value of contract settlements
    during the
    period(1)


204



38



242Change in fair value of contracts


514



154



668Assignment of contracts






36



36Other commodity-based derivatives
    subsequently designated as hedges


(16
)


16



Reclassification of derivatives
    that no longer qualify as hedges


6



(6
)


Option premiums
    paid(2)


6



69



75Net change in contracts
    outstanding during the period


714



307



1,021Fair value of contracts
    outstanding at December 31, 2006

$
61


$
(456
)

$
(395
)     (1)
    
    Includes derivative contracts
    sold/terminated.(2)
    
    Amounts are net of premiums
    received.  Fair Value of Contract Settlements.
  Changes in Fair Value of Contracts.
  Assignment of Contracts.
  Designation and Reclassifications of
    Hedges.
 69




---



##### Table of Contents



Critical
    Accounting Estimates
  Form 10-K.
  Accounting for Natural Gas and Oil Producing
    Activities.
    country-by-country
   70




---



##### Table of Contents



Accounting for Legal and Environmental
    Reserves.
    Accounting for Pension and Other Postretirement
    Benefits. Employers Accounting for Defined Benefit Pension and
    Other Postretirement Plans  an Amendment of FASB
    Statements No. 87, 88, 106 and 132(R).
   71




---



##### Table of Contents



Pension Benefits


Other Postretirement BenefitsChange in





Change in NetNet Asset





Liability and Pretaxand Pretax





Accumulated OtherNet Benefit


Accumulated Other


Net Benefit


ComprehensiveExpense (Income)


Comprehensive Loss


Expense (Income)


IncomeOne percent increase in:Discount rates

$
(12
)

$
(195
)

$



$
(38
)Expected return on plan assets


(22
)






(2
)


Rate of compensation increase


2



4







Health care cost trends










1



18One percent decrease in:Discount rates

$
12


$
232


$
(1
)

$
41Expected return on plan
    assets(1)


22







2



Rate of compensation increase


(2
)


(3
)






Health care cost trends










(1
)


(15
)     (1)
    
    If the actual return on plan assets
    was one percent lower than the expected return on plan assets,
    our expected cash contributions to our pension and other
    postretirement benefit plans would not significantly change.      Price Risk Management Activities.
 72




---



##### Table of Contents



10 Percent Increase


10 Percent DecreaseFair Value


Fair Value


Change


Fair Value


Change(In millions)Derivatives designated as hedges

$
61


$
(19
)

$
(80
)

$
144


$
83Other commodity-based derivatives


(456
)


(529
)


(73
)


(378
)


78Total

$
(395
)

$
(548
)

$
(153
)

$
(234
)

$
161     Asset and Investment Impairments.
  New
    Accounting Pronouncements Issued But Not Yet Adopted
  New Accounting
    Pronouncements Issued But Not Yet Adopted.
 73




---



##### Table of Contents



ITEM 7A.
    QUANTITATIVE
    AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK    
    Commodity Price Risk  
    Natural gas and oil price changes, impacting the sale of natural
    gas and oil in our Exploration and Production segment and gas
    not used in the operations of our Pipelines segment;  
    Natural gas locational price differences change, affecting our
    ability to optimize pipeline transportation capacity contracts
    held in our Marketing segment; and  
    Electricity and natural gas price changes and locational pricing
    changes, affecting the value of our natural gas contracts and
    remaining power contracts held in our Marketing segment.  
    Interest Rate Risk  
    Changes in interest rates affect the interest expense we incur
    on our variable-rate debt and the fair value of our fixed-rate
    debt;  
    Changes in interest rates used in the estimation of the fair
    value of our derivative positions can result in increases or
    decreases in the unrealized value of those positions; and  
    Changes in interest rates used to discount liabilities which can
    result in higher or lower accretion expense over time.  
    Foreign Currency Exchange Rate Risk  
    Weakening or strengthening of the U.S. dollar relative to
    the Euro can result in an increase or decrease in the value of
    our Euro-denominated debt obligations
    and/or the
    related interest costs associated with that debt    
    Forward contracts, which commit us to purchase or sell energy
    commodities in the future;
    Futures contracts, which are exchange-traded standardized
    commitments to purchase or sell a commodity or financial
    instrument, or to make a cash settlement at a specific price and
    future date;
    Options, which convey the right to buy or sell a commodity,
    financial instrument or index at a predetermined price;
    Swaps, which require payments to or from counterparties based
    upon the differential between two prices or rates for a
    predetermined contractual (notional) quantity; and
    Structured contracts, which may involve a variety of the above
    characteristics.    Commodity
    Price Risk
  Production-Related
    Derivatives
   74




---



##### Table of Contents



10 Percent Increase


10 Percent DecreaseFair Value


Fair Value


(Decrease)


Fair Value


IncreaseImpact of changes in commodity
    prices on production-related derivative instrumentsDecember 31, 2006

$
124


$
(9
)

$
(133
)

$
264


$
140December 31, 2005

$
(942
)

$
(1,175
)

$
(233
)

$
(713
)

$
229   Other
    Commodity-Based Derivatives
  Value-at-Risk one-day Value-at-Risk. one-day Value-at-Risk Value-at-Risk Value-at-Risk
  one-day Value-at-Risk one-day Value-at-Risk Value-at-Risk
 75




---



##### Table of Contents



Interest
    Rate Risk
    December 31, 2006


December 31, 2005Expected Fiscal Year of Maturity of Carrying Amounts


Fair


Carrying


Fair2007


2008


2009


2010


2011


Thereafter


Total


Value


Amounts


Value(In millions)Long-term debt and other
    obligations, including current portion  fixed rate

$
1,345


$
642


$
1,363


$
1,228


$
1,143


$
8,372


$
14,093


$
14,891


$
15,278


$
15,619Average interest rate


7.1
%


6.9
%


7.4
%


8.4
%


7.4
%


7.7
%Long-term debt and other
    obligations, including current portion  variable rate

$
13


$
13


$
214


$
160


$
16


$
180


$
596


$
596


$
1,988


$
1,988Average interest rate


6.2
%


6.2
%


7.1
%


5.4
%


6.2
%


6.2
%   Foreign
    Currency Exchange Rate Risk
   76




---



##### Table of Contents



ITEM 8.
    FINANCIAL
    STATEMENTS AND SUPPLEMENTARY DATA  Index
    PageManagements
    Annual Report on Internal Control over Financial
    Reporting


78Reports of
    Independent Registered Public Accounting Firms


79Consolidated
    Statements of Income


84Consolidated
    Balance Sheets


85Consolidated
    Statements of Cash Flows


87Consolidated
    Statements of Stockholders Equity


88Consolidated
    Statements of Comprehensive Income


89Notes to
    Consolidated Financial Statements


901.    Basis
    of Presentation and Significant Accounting Policies


902.    Divestitures


963.    (Gain)
    Loss on Long-Lived Assets


1014.    Other
    Income and Other Expenses


1025.    Income
    Taxes


1036.    Earnings
    Per Share


1067.    Fair
    Value of Financial Instruments


1078.    Price
    Risk Management Activities


1079.    Regulatory
    Assets and Liabilities


11110.  Other
    Assets and Liabilities


11211.  Property,
    Plant and Equipment


11312.  Debt,
    Other Financing Obligations and Credit Facilities


11513.  Commitments
    and Contingencies


11914.  Retirement
    Benefits


12415.  Stockholders
    Equity


12916.  Stock-Based
    Compensation


13017.  Business
    Segment Information


13218.  Investments
    in, Earnings from and Transactions with Unconsolidated
    Affiliates


135Supplemental Financial InformationSupplemental
    Selected Quarterly Financial Information (Unaudited)


139Supplemental
    Natural Gas and Oil Operations (Unaudited)


141Financial Statement ScheduleSchedule II 
    Valuation and Qualifying Accounts


148  77




---



##### Table of Contents



MANAGEMENTS
    ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL
    REPORTING    
    Pertain to the maintenance of records that, in reasonable
    detail, accurately and fairly reflect the transactions and
    dispositions of our assets;
    Provide reasonable assurance that transactions are recorded as
    necessary to permit preparation of the financial statements in
    accordance with generally accepted accounting principles, and
    that our receipts and expenditures are being made only in
    accordance with authorizations of our management and
    directors; and
    Provide reasonable assurance regarding prevention or timely
    detection of unauthorized acquisition, use or disposition of our
    assets that could have a material effect on the financial
    statements.  Internal Control 
    Integrated Framework
 78




---



##### Table of Contents



REPORT OF
    INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
  
        Share-Based Payment Employers Accounting for Defined Benefit
    Pension and Other Postretirement Plans  An Amendment
    of FASB Statements No. 87, 88, 106, and 132(R).
    
    79




---



##### Table of Contents



REPORT OF
    INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON INTERNAL
    CONTROL OVER FINANCIAL REPORTING
  
              
    80




---



##### Table of Contents



REPORT OF
    INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM       Accounting for Conditional Asset Retirement Obligations,
  PricewaterhouseCoopers
    LLP
       81




---



##### Table of Contents



Report of
    Independent Registered Public Accounting Firm
        PricewaterhouseCoopers
    LLP
    82




---



##### Table of Contents



Report of
    Independent Registered Public Accounting Firm
        PricewaterhouseCoopers
    LLP
    83




---



##### Table of Contents



EL PASO
    CORPORATION



CONSOLIDATED
    STATEMENTS OF INCOME

(In
    millions, except per common share amounts)  Year Ended December 31,2006


2005


2004Operating revenuesPipelines

$
2,402


$
2,171


$
2,145Exploration and Production


1,854



1,787



1,735Marketing


(58
)


(796
)


(508
)Power


6



82



402Field Services






123



1,097Corporate and eliminations


77



(8
)


(88
)4,281



3,359



4,783Operating expensesCost of products and services


238



245



1,168Operation and maintenance


1,319



1,861



1,565Depreciation, depletion and
    amortization


1,047



1,006



962Loss on long-lived assets


18



74



1,077Taxes, other than income taxes


232



234



1972,854



3,420



4,969Operating income (loss)


1,427



(61
)


(186
)Earnings from unconsolidated
    affiliates


145



281



479Other income


245



285



175Other expenses


(67
)


(47
)


(94
)Interest and debt expense


(1,228
)


(1,286
)


(1,497
)Distributions on preferred
    interests of consolidated subsidiaries






(9
)


(25
)Income (loss) before income taxes
    from continuing operations


522



(837
)


(1,148
)Income taxes


(9
)


(331
)


(116
)Income (loss) from continuing
    operations


531



(506
)


(1,032
)Discontinued operations, net of
    income taxes


(56
)


(96
)


85Cumulative effect of accounting
    changes, net of income taxes






(4
)


Net income (loss)


475



(606
)


(947
)Preferred stock dividends


37



27



Net income (loss) available to
    common stockholders

$
438


$
(633
)

$
(947
)Basic earnings (loss) per common
    shareIncome (loss) from continuing
    operations

$
0.73


$
(0.82
)

$
(1.61
)Discontinued operations, net of
    income taxes


(0.08
)


(0.15
)


0.13Cumulative effect of accounting
    changes, net of income taxes






(0.01
)


Net income (loss) per common share

$
0.65


$
(0.98
)

$
(1.48
)Diluted earnings (loss) per common
    shareIncome (loss) from continuing
    operations

$
0.72


$
(0.82
)

$
(1.61
)Discontinued operations, net of
    income taxes


(0.08
)


(0.15
)


0.13Cumulative effect of accounting
    changes, net of income taxes






(0.01
)


Net income (loss) per common share

$
0.64


$
(0.98
)

$
(1.48
)    84




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##### Table of Contents



EL PASO
    CORPORATION



CONSOLIDATED
    BALANCE SHEETS

(In
    millions, except share amounts)  December 31,2006


2005ASSETSCurrent assetsCash and cash equivalents

$
537


$
2,132Accounts and notes receivableCustomer, net of allowance of $28
    in 2006 and $65 in 2005


516



1,025Affiliates


192



59Other


495



146Assets from price risk management
    activities


436



641Margin and other deposits held by
    others


60



1,124Assets held for sale and from
    discontinued operations


4,161



349Deferred income taxes


478



391Other


292



318Total current assets


7,167



6,185Property, plant and equipment, at
    costPipelines


15,672



14,767Natural gas and oil properties, at
    full cost


16,572



15,738Other


566



65132,810



31,156Less accumulated depreciation,
    depletion and amortization


16,132



15,604Total property, plant and
    equipment, net


16,678



15,552Other assetsInvestments in unconsolidated
    affiliates


1,707



2,165Assets from price risk management
    activities


414



1,368Assets from discontinued operations






4,300Other


1,295



2,2703,416



10,103Total assets

$
27,261


$
31,840    85




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##### Table of Contents



EL PASO
    CORPORATION
  CONSOLIDATED
    BALANCE SHEETS
 (In
    millions, except share amounts)
  December 31,2006


2005LIABILITIES AND STOCKHOLDERS
    EQUITYCurrent liabilitiesAccounts payableTrade

$
478


$
807Affiliates


3



3Other


569



519Short-term financing obligations,
    including current maturities


1,360



984Liabilities from price risk
    management activities


278



1,418Liabilities related to
    discontinued operations


1,817



563Margin deposits held by us


344



497Accrued interest


269



274Other


1,033



647Total current liabilities


6,151



5,712Long-term financing obligations,
    less current maturities


13,329



16,282OtherLiabilities from price risk
    management activities


924



2,005Deferred income taxes


950



549Liabilities related to
    discontinued operations






1,669Other


1,690



2,2033,564



6,426Commitments and contingenciesSecurities of subsidiaries


31



31Stockholders equityPreferred stock, par value
    $0.01 per share; authorized 50,000,000 shares; issued
    750,000 shares of 4.99% convertible perpetual stock;
    stated at liquidation value


750



750Common stock, par value
    $3 per share; authorized 1,500,000,000 shares; issued
    705,833,206 shares in 2006 and 667,082,043 shares in
    2005


2,118



2,001Additional paid-in capital


4,804



4,592Accumulated deficit


(2,940
)


(3,415
)Accumulated other comprehensive
    loss


(343
)


(332
)Treasury stock (at cost);
    8,715,288 shares in 2006 and 7,620,272 shares in 2005


(203
)


(190
)Unamortized compensation






(17
)Total stockholders equity


4,186



3,389Total liabilities and
    stockholders equity

$
27,261


$
31,840    86




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##### Table of Contents



EL PASO
    CORPORATION



CONSOLIDATED
    STATEMENTS OF CASH FLOWS

(In
    millions)  Year Ended December 31,2006


2005


2004Cash flows from operating activitiesNet income (loss)

$
475


$
(606
)

$
(947
)Less income (loss) from
    discontinued operations, net of income taxes


(56
)


(96
)


85Net income (loss) before
    discontinued operations


531



(510
)


(1,032
)Adjustments to reconcile net income
    (loss) to net cash from operating activitiesDepreciation, depletion and
    amortization


1,047



1,006



962Deferred income tax benefit


(20
)


(303
)


(140
)Loss on long-lived assets


18



74



1,077Earnings from unconsolidated
    affiliates, adjusted for cash distributions


(6
)


(78
)


(219
)Other non-cash income items


80



356



433Asset and liability changesAccounts and notes receivable


344



122



491Change in price risk management
    activities, net


(420
)


325



191Accounts payable


(382
)


(118
)


(334
)Change in margin and other deposits


911



(679
)


97Western Energy Settlement liability






(395
)


(626
)Other asset changes


(179
)


177



11Other liability changes


(100
)


(10
)


(252
)Cash provided by (used in)
    continuing activities


1,824



(33
)


659Cash provided by discontinued
    activities


279



301



657Net cash provided by operating
    activities


2,103



268



1,316Cash flows from investing activitiesCapital expenditures


(2,164
)


(1,589
)


(1,651
)Cash paid for acquisitions, net of
    cash acquired






(1,025
)


(50
)Net proceeds from the sale of
    assets and investments


673



1,424



1,927Net change in restricted cash


129



(57
)


552Other


23



204



134Cash provided by (used in)
    continuing activities


(1,339
)


(1,043
)


912Cash provided by discontinued
    activities


185



542



991Net cash provided by (used in)
    investing activities


(1,154
)


(501
)


1,903Cash flows from financing activitiesNet proceeds from issuance of
    long-term debt


375



1,620



1,254Payments to retire long-term debt
    and other financing obligations


(3,024
)


(1,491
)


(3,052
)Repayment of notes payable










(214
)Net proceeds from the issuance of
    common stock


500







73Dividends paid


(145
)


(121
)


(101
)Net proceeds from issuance of
    preferred stock






723



Payments to minority interest and
    preferred interest holders


(5
)


(306
)


(35
)Contributions from discontinued
    operations


232



666



1,225Other


(13
)






(33
)Cash provided by (used in)
    continuing activities


(2,080
)


1,091



(883
)Cash used in discontinued activities


(464
)


(843
)


(1,648
)Net cash provided by (used in)
    financing activities


(2,544
)


248



(2,531
)Change in cash and cash equivalents


(1,595
)


15



688Cash and cash equivalentsBeginning of period


2,132



2,117



1,429End of period

$
537


$
2,132


$
2,117Supplemental cash flow information
    related to continuing operationsInterest paid, net of amounts
    capitalized

$
1,217


$
1,238


$
1,431Income tax payments


77



11



37    87




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##### Table of Contents



EL PASO
    CORPORATION



CONSOLIDATED
    STATEMENTS OF STOCKHOLDERS EQUITY

(In
    millions, except per share amounts)  Year Ended December 31,2006


2005


2004Shares


Amount


Shares


Amount


Shares


AmountPreferred stock, $0.01 par
    value:Balance at beginning of year


1


$
750






$







$
Equity offering










1



750







Balance at end of year


1



750



1



750







Common stock, $3.00 par value:Balance at beginning of year


667



2,001



651



1,953



639



1,917Exchange of equity security units










14



41







Equity offering


36



107















Other, net


3



10



2



7



12



36Balance at end of year


706



2,118



667



2,001



651



1,953Additional paid-in capital:Balance at beginning of year






4,592







4,538







4,576Equity offering






393















Dividends






(147
)






(131
)






(104
)Compensation related issuances






(2
)






(18
)






15Tax effects of equity plans














2







5Exchange of equity security units














230







Other






(32
)






(29
)






46Balance at end of year






4,804







4,592







4,538Accumulated deficit:Balance at beginning of year






(3,415
)






(2,809
)






(1,862
)Net income (loss)






475







(606
)






(947
)Balance at end of year






(2,940
)






(3,415
)






(2,809
)Accumulated other comprehensive
    income (loss):Balance at beginning of year






(332
)






1







(40
)Other comprehensive income (loss)






380







(333
)






41Cumulative effect of adopting
    SFAS No. 158, net of income tax of $210






(391
)














Balance at end of year






(343
)






(332
)






1Treasury stock, at cost:Balance at beginning of year


(8
)


(190
)


(8
)


(225
)


(7
)


(222
)Compensation related issuances










1



47







9Other


(1
)


(13
)


(1
)


(12
)


(1
)


(12
)Balance at end of year


(9
)


(203
)


(8
)


(190
)


(8
)


(225
)Unamortized compensation:Balance at beginning of year






(17
)






(20
)






(23
)Issuance of restricted stock














(22
)






(28
)Amortization of restricted stock














18







23Forfeitures of restricted stock














7







9Adoption of SFAS No. 123(R),






17















(1
)Balance at end of year














(17
)






(20
)Total stockholders equity


697


$
4,186



659


$
3,389



643


$
3,438    88




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##### Table of Contents



EL PASO
    CORPORATION



CONSOLIDATED
    STATEMENTS OF COMPREHENSIVE INCOME

(In
    millions)  Year Ended December 31,2006


2005


2004Net income (loss)

$
475


$
(606
)

$
(947
)Foreign currency translation
    adjustments (net of
    income tax benefits of less than $1 in 2006, $13 in 2005 and
    $38
    in 2004)


4



(9
)


11Change in minimum pension
    liability (net of income
    tax of $3 in 2006, $2 in 2005, and $11 in 2004)


5



(3
)


(22
)Net gains (losses) from cash flow
    hedging activities:Unrealized
    mark-to-market
    gains (losses) arising during period
    (net of income tax of $196 in 2006, $229 in 2005, and $8 in 2004)


352



(415
)


22Reclassification adjustments for
    changes in initial value to settlement date (net of income tax
    of $15 in 2006, $46 in 2005, and $8 in 2004)


22



79



30Net gains from investments
    available for sale:Unrealized gains arising during
    period (net of income tax of $16 in 2006 and $9 in 2005)


28



15



Realized gains reclassified from
    accumulated other comprehensive income during period (net of
    income tax of $17 in 2006)


(31
)






Other comprehensive income (loss)


380



(333
)


41Comprehensive income (loss)

$
855


$
(939
)

$
(906
)    89




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##### Table of Contents



EL PASO
    CORPORATION
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS
  1.
    Basis of
    Presentation and Significant Accounting Policies  Basis of
    Presentation and Principles of Consolidation
    and/or and/or and/or
  Use of
    Estimates
    Regulated
    Operations
  Accounting for the
    Effects of Certain Types of Regulation.
  Cash and
    Cash Equivalents
     90




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##### Table of Contents



Allowance
    for Doubtful Accounts
    Property,
    Plant and Equipment
  Pipelines and Other (Excluding Natural Gas and Oil
    Properties).
      Natural Gas and Oil Properties.
    end-of-period
 91




---



##### Table of Contents



Asset and
    Investment Divestitures/ Impairments
    held-for-sale
  Pension
    and Other Postretirement Benefits
    Employers
    Accounting for Defined Benefit Pension and Other Postretirement
    Plans  an Amendment of FASB Statements No. 87,
    88, 106 and 132(R).
  Revenue
    Recognition
    Pipelines revenues.
 92




---



##### Table of Contents



Exploration and Production revenues.
  Marketing revenues. Price Risk Management Activities
  Environmental
    Costs and Other Contingencies
  Environmental Costs. clean-up clean-up
    Other Contingencies.
  Price
    Risk Management Activities
    
    derivatives entered into to hedge or otherwise reduce the
    commodity exposure on our natural gas and oil production and
    interest rate and foreign currency exposure on our long-term
    debt; and 93




---



##### Table of Contents




    derivatives not intended to hedge these exposures, including
    those related to our historical trading activities that we
    entered into with the objective of generating profits from
    exposure to shifts or changes in market prices.    marked-to-market
    Income
    Taxes
    Foreign
    Currency Translation
    Accounting
    for Asset Retirement Obligations
  Accounting for Asset Retirement
    Obligations
  Accounting
    for Stock-Based Compensation.
  Share-Based Payment
 94




---



##### Table of Contents



Accounting for
    Stock Issued to Employees,
      Year EndedDecember 31,2005


2004(In millions, except per common share amounts)Net loss available to common
    stockholders, as reported

$
(633
)

$
(947
)Add: Stock-based employee
    compensation expense included in reported net loss, net of taxes


12



14Deduct: Total stock-based
    compensation expense determined under fair-value based method
    for all awards, net of taxes


(19
)


(25
)Net loss available to common
    stockholders, pro forma

$
(640
)

$
(958
)Loss per share:Basic and diluted, as reported

$
(0.98
)

$
(1.48
)Basic and diluted, pro forma

$
(0.99
)

$
(1.50
)   Evaluation
    of Prior Period Misstatements in Current Financial
    Statements
  Considering the Effects of Prior
    Year Misstatements When Quantifying Misstatements in Current
    Year Financial Statements.
  New
    Accounting Pronouncements Issued But Not Yet Adopted
    Accounting for Uncertainty in Income Taxes. Accounting for
    Uncertainty in Income Taxes. Accounting for Income Taxes,
 95




---



##### Table of Contents



Fair Value Measurements. Fair Value
    Measurements
  Measurement Date of Pension and Other Postretirement
    Benefits.
  Fair Value Option for
    Financial Assets and Financial Liabilities Accounting for Certain Investments in Debt and Equity
    Securities
  2.
    Acquisitions
    and Divestitures  Acquisitions
  South Texas properties.
  Medicine Bow.
    Year EndedDecember 31,2005(1)


2004(In millions, except per share amounts)Revenues

$
3,398


$
4,833Net income


(623
)


(958
)Basic and diluted loss per common
    share


(0.96
)


(1.50
)     (1)
    
    Excludes a $13 million pre-tax
    charge for change in control payments triggered at Medicine Bow
    as a result of the acquisition. 96




---



##### Table of Contents



Divestitures
    2006


2005


2004(In millions)Power

$
531


$
625


$
884Field Services






657



1,029Exploration and Production


122



7



24Pipelines


3



49



59Corporate


2



121



16Total
    continuing(1)


658



1,459



2,012Discontinued


368



577



1,295Total

$
1,026


$
2,036


$
3,307     (1)
    
    Proceeds exclude returns of
    invested capital and cash transferred with the assets sold and
    include costs incurred in preparing assets for disposal. These
    items increased our sales proceeds by $15 million for the
    year ended December 31, 2006, and decreased our sales
    proceeds by $35 million and $85 million for the years
    ended December 31, 2005 and 2004.  Power.
  Field Services.
  Exploration and Production, Pipelines, and
    Corporate.
    Discontinued
    Operations and Assets Held for Sale
  Accounting for the Impairment
    or Disposal of Long-Lived Assets
 97




---



##### Table of Contents



ANR and Related Operations.
  International Power Operations.
  South Louisiana Gathering and Processing
    Operations.
  Other.
  Income Taxes on Discontinued Operations.
  
    In 2006, we recorded approximately $188 million of deferred
    taxes upon agreeing to sell the stock of ANR, our Michigan
    storage assets and our 50 percent interest in Great Lakes
    Gas Transmission. Prior to our decision to sell, we were only
    required to record deferred taxes on individual
    assets/liabilities and a portion of our investment in the stock
    of one of these companies;
    In 2005, impairments and operating losses of certain foreign
    investments for which no tax benefit was available, dividends
    from foreign subsidiaries taxable in the U.S. and state income
    taxes; and
    In 2004, impairments and operating losses of certain foreign
    investments, for which no tax benefit was available and state
    income taxes. 98




---



##### Table of Contents



SouthLouisianaGatheringANR and


International


andRelated


Power


ProcessingOperations


Operations


Operations


Other


Total(In millions)Year Ended December 31,
    2006Revenues

$
581


$
149


$



$



$
730Costs and expenses


(334
)


(159
)










(493
)Gain (loss) on long-lived assets






(11
)


5







(6
)Other income


63



3











66Interest and debt expense


(65
)


(14
)










(79
)Income (loss) before income taxes

$
245


$
(32
)

$
5


$




218Income taxes


















274Loss from discontinued operations,
    net of income taxes

















$
(56
)Year Ended December 31,
    2005Revenues

$
612


$
207


$
292


$
127


$
1,238Costs and expenses


(372
)


(216
)


(264
)


(182
)


(1,034
)Gain (loss) on long-lived assets






(510
)


394



2



(114
)Other income


62



13







12



87Interest and debt expense


(68
)


(26
)










(94
)Income (loss) before income taxes

$
234


$
(532
)

$
422


$
(41
)


83Income taxes


















179Loss from discontinued operations,
    net of income taxes

















$
(96
)Year Ended December 31,
    2004Revenues

$
506


$
393


$
265


$
818


$
1,982Costs and expenses


(304
)


(225
)


(229
)


(892
)


(1,650
)Loss on long-lived assets






(30
)






(58
)


(88
)Other income


70



10







15



95Interest and debt expense


(71
)


(39
)






(2
)


(112
)Income (loss) before income taxes

$
201


$
109


$
36


$
(119
)


227Income taxes


















142Income from discontinued
    operations, net of income taxes

















$
85   99




---



##### Table of Contents



SouthLouisianaGatheringANR and


International


andRelated


Power


ProcessingOperations


Operations


Operations


Other


Total(In millions)December 31,
    2006Assets of discontinued operationsAccounts and notes receivable

$
19


$



$



$



$
19Other current assets


757















757Property, plant and equipment, net


3,357















3,357Total assets

$
4,133


$



$



$



$
4,133Liabilities of discontinued
    operationsAccounts payable

$
64


$



$



$



$
64Other current liabilities


160















160Long-term debt


741















741Deferred income taxes


852















852Total liabilities

$
1,817


$



$



$



$
1,817December 31,
    2005Assets of discontinued operationsAccounts and notes receivable

$
90


$
25


$



$



$
115Other current assets


30



204











234Property, plant and equipment, net


3,235



351











3,586Other non-current assets


711



3











714Total assets

$
4,066


$
583


$



$



$
4,649Liabilities of discontinued
    operationsAccounts payable

$
94


$
206


$



$



$
300Other current liabilities


47



216











263Long-term debt


741















741Deferred income taxes


859















859Other non-current liabilities


69















69Total liabilities

$
1,810


$
422


$



$



$
2,232  100




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##### Table of Contents



3.
    (Gain)
    Loss on Long-Lived Assets    2006


2005


2004(In millions)Net realized (gain) loss

$
2


$
1


$
(16
)Asset impairmentsPowerBrazilian assets










183Domestic power assets










397Turbines






18



1PipelinesPipeline development projects


16



46



Field ServicesGoodwill impairment










480Other






9



23Other










9Total asset impairments


16



73



1,093Loss on long-lived assets


18



74



1,077Gain on sale of investments in
    unconsolidated affiliates, net of impairments


(6
)


(91
)


(124
)(Gain) loss on assets and
    investments

$
12


$
(17
)

$
953  101




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##### Table of Contents



4.
    Other
    Income and Other Expenses    2006


2005


2004(In millions)Other IncomeInterest income

$
138


$
125


$
88Allowance for funds used during
    construction


31



31



22Development, management and
    administrative services fees on power projects from affiliates


7



11



14Foreign currency gain






36



14Gain on sale of cost basis
    investments


47



40



Dividend income


14



19



Other


8



23



37Total

$
245


$
285


$
175Other ExpensesForeign currency losses

$
20


$



$
26Loss on early extinguishment of
    debt


26



29



12Loss on sale of cost basis
    investments


12







Minority interest in consolidated
    subsidiaries


1



1



38Other


8



17



18Total

$
67


$
47


$
94  102




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##### Table of Contents



5.
    Income
    Taxes  Pretax Income (Loss) and Income Tax Expense
    (Benefit).
  2006


2005


2004(In millions)Pretax Income (Loss)U.S.

$
442


$
(872
)

$
(952
)Foreign


80



35



(196
)$
522


$
(837
)

$
(1,148
)Components of Income Tax
    Expense (Benefit)CurrentFederal

$
7


$
(13
)

$
(17
)State


(15
)


(37
)


33Foreign


19



22



811



(28
)


24DeferredFederal


(46
)


(372
)


(133
)State


32



67



(8
)Foreign


(6
)


2



1(20
)


(303
)


(140
)Total income taxes

$
(9
)

$
(331
)

$
(116
)   Effective Tax Rate Reconciliation.
  2006


2005


2004(In millions, except rates)Income taxes at the statutory
    federal rate of 35%

$
183


$
(293
)

$
(402
)Increase (decrease)Audit settlements


(159
)


(58
)


Earnings from unconsolidated
    affiliates where we anticipate receiving dividends


(35
)


(36
)


(17
)State income taxes, net of federal
    income tax effect


20



(16
)


(1
)Sales and write-offs of foreign
    investments


(17
)


(7
)


14Foreign income taxed at different
    rates


(13
)


75



132IRS interest refund


(11
)






Valuation allowances


23



34



18Non-deductible goodwill impairments










139Non-taxable medicare reimbursements


(6
)


(25
)


Other


6



(5
)


1Income taxes

$
(9
)

$
(331
)

$
(116
)Effective tax rate


(2
)%


40
%


10
%  103




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##### Table of Contents



1998-2000
    Deferred Tax Assets and Liabilities.
  2006


2005(In millions)Deferred tax liabilitiesProperty, plant and equipment

$
2,736


$
2,423Investments in affiliates


555



205Regulatory and other assets


53



302Total deferred tax liability


3,344



2,930Deferred tax assetsNet operating loss and tax credit
    carryoversFederal


1,560



1,098State


214



204Foreign


81



49Environmental liability


144



147Price risk management activities


284



573Legal and other reserves


332



266Other


424



574Valuation allowance


(127
)


(107
)Total deferred tax asset


2,912



2,804Net deferred tax liability

$
432


$
126    104




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##### Table of Contents



Tax Credit and NOL Carryovers.
  Carryover Period2007


2008-2011


2012-2016


2017-2026


Total(In millions)U.S. federal net operating
    loss

$



$
16


$
7


$
3,626


$
3,649State net operating loss


182



1,013



496



999



2,690     Valuation Allowances.
  Other Tax Matters.
 105




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##### Table of Contents



6.
    Earnings
    Per Share    2006


2005


2004Basic


Diluted


Basic


Diluted


Basic


Diluted(In millions, except per share amounts)Income (loss) from continuing
    operations

$
531


$
531


$
(506
)

$
(506
)

$
(1,032
)

$
(1,032
)Convertible preferred stock
    dividends


(37
)






(27
)


(27
)






Income (loss) from continuing
    operations available to common stockholders


494



531



(533
)


(533
)


(1,032
)


(1,032
)Discontinued operations


(56
)


(56
)


(96
)


(96
)


85



85Cumulative effect of accounting
    changes, net of income taxes










(4
)


(4
)






Net income (loss) available to
    common stockholders

$
438


$
475


$
(633
)

$
(633
)

$
(947
)

$
(947
)Weighted average common shares
    outstanding


678



678



646



646



639



639Effect of dilutive securities:Options and restricted stock






4















Convertible preferred stock






57















Weighted average common shares
    outstanding and dilutive potential common shares


678



739



646



646



639



639Earnings per common share:Income (loss) from continuing
    operations

$
0.73


$
0.72


$
(0.82
)

$
(0.82
)

$
(1.61
)

$
(1.61
)Discontinued operations, net of
    income taxes


(0.08
)


(0.08
)


(0.15
)


(0.15
)


0.13



0.13Cumulative effect of accounting
    changes, net of income taxes










(0.01
)


(0.01
)






Net income (loss)

$
0.65


$
0.64


$
(0.98
)

$
(0.98
)

$
(1.48
)

$
(1.48
)    106




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##### Table of Contents



7.
    Fair
    Value of Financial Instruments  As of December 31,2006


2005Carrying


Fair


Carrying


FairAmount


Value


Amount


Value(In millions)Long-term financing obligations,
    including current maturities

$
14,689


$
15,487


$
17,266


$
17,607Commodity-based price risk
    management derivatives


(395
)


(395
)


(1,416
)


(1,416
)Interest rate and foreign currency
    derivatives


43



43



2



2Investments


23



23



61



61     8.
    Price
    Risk Management Activities    As of December 31,2006


2005(In millions)Net assets (liabilities)Derivatives designated as hedges

$
61


$
(653
)Other commodity-based derivative
    contracts


(456
)


(763
)Total commodity-based
    derivatives(1)


(395
)


(1,416
)Interest rate and foreign currency
    derivatives


43



2Net liabilities from price risk
    management
    activities(2)

$
(352
)

$
(1,414
)     (1)
    
    Decrease is due primarily to the
    sale or assignment of a number of derivative contracts and
    significant changes in natural gas and oil prices during 2006.(2)
    
    Included in both current and
    non-current assets and liabilities on the balance sheet.   107




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##### Table of Contents



Derivatives
    Designated as Hedges
    Cash Flow Hedges.
  AccumulatedOther


EstimatedComprehensive


Income (Loss)


FinalIncome (Loss)


Reclassification


Termination2006


2005


in
    2007(1)


Year(In millions)Commodity cash flow
    hedgesHeld by consolidated entities

$
49


$
(285
)

$
89



2012Held by unconsolidated affiliates


(4
)


(7
)


(1
)


2013De-designated(2)


35







35



2007Total commodity cash flow hedges


80



(292
)


123Interest rate and foreign
    currency cash flow hedgesFixed rate


3



2



1



2015De-designated


(3
)


(4
)






2009Total foreign currency cash flow
    hedges






(2
)


1Total cash flow hedges

$
80


$
(294
)

$
124     (1)
    
    Reclassifications occur upon the
    physical delivery of the hedged commodity or if the forecasted
    transaction is no longer probable.(2)
    
    During 2006, we removed the hedging
    designation on certain derivatives that hedged approximately 75
    Tbtu and 154 MBbls of our natural gas and oil production in
    2007.   108




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##### Table of Contents



Fair Value Hedges.
  Price Risk ManagementWeighted


Debt


Asset
    (Liability)(1)Derivative

Average Rate


2006


2005


2006


2005Fixed-to-floating
    swaps


LIBOR + 4.18
%

$
440


$
440


$
(31
)

$
(30
)Fixed-to-floating
    cross currency
    swaps(2)


LIBOR + 4.24
%


402



402



67



23$
36


$
(7
)     (1)
    
    We did not record any
    ineffectiveness related to our fair value hedges in 2004, 2005
    or 2006.  (2)
    
    As of December 31, 2006 and
    2005, these derivatives, when combined with our Euro denominated
    debt, converted 350 million Euro of our debt to
    $402 million.  Other
    Commodity-Based Derivatives.
    Credit
    Risk
     109




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##### Table of Contents



Below


NotCounterparty

Investment
    Grade(1)


Investment
    Grade(1)


Rated(1)


Total(In millions)December 31,
    2006Energy marketers

$
136


$
81


$



$
217Natural gas and electric utilities


6







64



70Commodity exchanges


321











321Financial institutions and other


153







1



154Net financial instrument
    assets(2)


616



81



65



762Collateral held by us


(328
)


(78
)


(64
)


(470
)Net exposure from derivative assets

$
288


$
3


$
1


$
292   Below


NotCounterparty

Investment
    Grade(1)


Investment
    Grade(1)


Rated(1)


Total(In millions)December 31,
    2005Energy marketers

$
554


$
110


$



$
664Natural gas and electric utilities


6







134



140Commodity exchanges


533











533Financial institutions and other


27







1



28Net financial instrument
    assets(2)


1,120



110



135



1,365Collateral held by us


(831
)


(96
)


(68
)


(995
)Net exposure from derivative assets

$
289


$
14


$
67


$
370     (1)
    
    Investment Grade and
    Below Investment Grade are determined using publicly
    available credit ratings. Investment Grade includes
    counterparties with a minimum Standard & Poors
    rating of BBB  or Moodys rating of Baa3.
    Below Investment Grade includes counterparties with
    a public credit rating that do not meet the criteria of
    Investment Grade. Not Rated includes
    counterparties that are not rated by any public rating service.     110




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##### Table of Contents



9.
    Regulatory
    Assets and Liabilities    2006


2005(In millions)Current regulatory assets

$
6


$
4Non-current regulatory assetsGross-up
    of deferred taxes on capitalized funds used during construction


106



96Postretirement benefits


22



25Unamortized net loss on reacquired
    debt


19



20Under-collected state income tax


3



7Other


21



16Total non-current regulatory assets


171



164Total regulatory assets

$
177


$
168Current regulatory liabilities

$
16


$
9Non-current regulatory liabilitiesEnvironmental liability


130



110Cost of removal of offshore assets


12



48Property and plant depreciation


70



41Postretirement benefits


19



16Plant regulatory liability


11



11Excess deferred income taxes


6



6Other


4



8Total non-current regulatory
    liabilities


252



240Total regulatory liabilities

$
268


$
249  111




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##### Table of Contents



10.
    Other
    Assets and Liabilities    2006


2005(In millions)Other current assetsPrepaid expenses

$
72


$
85Restricted cash (Note 1)


8



92Inventory


115



118Deposits


60



Other


37



23Total

$
292


$
318Other non-current assetsPension, other postretirement and
    postemployment benefits (Note 14)

$
332


$
886Notes receivable from affiliates


232



263Restricted cash (Note 1)


123



168Unamortized debt expenses


133



164Regulatory assets (Note 9)


171



164Long-term receivables


131



410Other


173



215Total

$
1,295


$
2,270Other current liabilitiesAccrued taxes, other than income

$
95


$
95Income taxes


17



58Environmental, legal and rate
    reserves (Note 13)


560



174Deposits


30



21Pension and other postretirement
    benefit (Note 14)


30



35Accrued lease obligations


56



43Asset retirement obligations
    (Note 11)


89



31Dividends payable


37



35Accrued liabilities


26



36Other


93



119Total

$
1,033


$
647Other non-current liabilitiesEnvironmental and legal reserves
    (Note 13)

$
616


$
1,004Pension, other postretirement and
    postemployment benefits (Note 14)


294



224Regulatory liabilities
    (Note 9)


252



240Asset retirement obligations
    (Note 11)


154



178Other deferred credits


159



183Insurance reserves


118



132Other


97



242Total

$
1,690


$
2,203  112




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##### Table of Contents



11. Property,
    Plant and Equipment  Depreciable lives.
  Method

Depreciable Lives(In years)Regulated interstate systems

Composite


(1
)Non-regulated assetsNatural gas and oil properties

(2)


(2
)Transmission and storage facilities

Straight-line


5-27Gathering and processing systems

Straight-line


40Transportation equipment

Straight-line


6Buildings and improvements

Straight-line


4-49Office and miscellaneous equipment

Straight-line


1-28     (1)
    
    Under the composite (group) method,
    assets with similar useful lives and other characteristics are
    grouped and depreciated as one asset. We apply the depreciation
    rate approved in our rate settlements to the total cost of the
    group until its net book value equals its salvage value. We
    re-evaluate depreciation rates each time we redevelop our
    transportation rates when we file with the FERC for an increase
    or decrease in rates.(2)
    
    Capitalized costs associated with
    proved reserves are amortized over the life of the reserves
    using the unit of production method. Conversely, capitalized
    costs associated with unproved properties are excluded from the
    amortizable base until these properties are evaluated. See
    Note 1 for additional information.  Excess purchase cost.
  Capitalized costs during construction.
  Construction work-in progress. work-in-progress
 113




---



##### Table of Contents



Asset retirement obligations.
    2006


2005(In millions)Net asset retirement liability at
    January 1

$
252


$
309Liabilities
    settled(1)


(48
)


(92
)Accretion expense


19



27Liabilities incurred


5



12Changes in estimate


15



(12
)Adoption of
    FIN No. 47(2)






8Net asset retirement liability at
    December 31

$
243


$
252     (1)
    
    Decrease is due primarily to the
    sale of certain domestic natural gas and oil properties in our
    Exploration and Production segment in 2005. See Note 2.  (2)
    
    We recorded a charge in 2005 of
    $4 million net of income taxes of $2 million as a
    cumulative effect of accounting change upon our adoption of
    FIN No. 47 (primarily related to our Pipelines segment
    and our corporate activities). If we had adopted the provisions
    of FIN No. 47 as of January 1, 2004, our net
    income for the years ended December 31, 2004 and 2005 would
    not have been materially affected. 114




---



##### Table of Contents



12.
    Debt,
    Other Financing Obligations and Other Credit
    Facilities  Year Ended December 31,2006


2005(In millions)Short-term financing obligations,
    including current maturities

$
1,360


$
984Long-term financing obligations


13,329



16,282Total(1)

$
14,689


$
17,266     Colorado Interstate Gas CompanyNotes, 5.95% through 6.85%, due
    2015 through 2037

$
700


$
700El Paso CorporationNotes, 6.375% through 10.75%, due
    2007 through 2037


7,939



8,212Zero coupon convertible debentures






611$1.25 billion term loan,
    LIBOR plus 2.75%






1,225$1.25 billion revolver, LIBOR
    plus 1.75% due 2009


200



El Paso Natural Gas CompanyNotes, 7.5% through 8.625%, due
    2010 through 2032


1,115



1,115El Paso
    Exploration & Production CompanySenior note, 7.75%, due 2013


1,200



1,200Revolving credit facility,
    variable due 2010


145



500Southern Natural Gas CompanyNotes, 6.125% through 8.875%, due
    2007 through 2032


1,200



1,200Tennessee Gas Pipeline CompanyNotes, 6.0% through 8.375%, due
    2011 through 2037


1,626



1,626Other


310



32314,435



16,712Other financing obligationsCapital Trust I, due 2028


325



325Coastal Finance I






300325



625Subtotal


14,760



17,337Less:Other, including unamortized
    discounts and premiums


71



71Current maturities


1,360



984Total long-term financing
    obligations, less current
    maturities(1)

$
13,329


$
16,282     (1)
    
    Excludes $741 and $967 million
    of debt related to our discontinued operations in 2006 and 2005. 115




---



##### Table of Contents



Changes in Long-Term Financing
    Obligations.
  Book Value


CashCompany

Type

Interest Rate

Increase (Decrease)


Received/(Paid)(In millions)IssuancesEPEP

Revolving credit facility due 2010

Variable

$
175


$
175El Paso

Revolving credit facility due 2009

LIBOR + 1.75%


200



200Increases through
    December 31, 2006

$
375


$
375Repayments, repurchases,
    retirements and otherCoastal Finance I

Trust originated preferred
    securities

8.375%

$
(300
)

$
(300
)El Paso

Zero coupon convertible debentures




(615
)


(615
)El Paso

Euro notes

5.75%


(26
)


(26
)EPEP

Revolving credit facility

Variable


(530
)


(530
)El Paso

Notes

6.50%-7.50%


(315
)


(315
)Macae(1)

Non-recourse notes

Variable


(229
)


(229
)El Paso

Term Loan

LIBOR + 2.75%


(1,225
)


(1,225
)Other

Long-term debt

Various


59



(13
)Decreases through
    December 31, 2006

$
(3,181
)

$
(3,253
)     (1)
    
    Included in liabilities related to
    discontinued operations on our balance sheet at
    December 31, 2005.    Debt Maturities.
  2007

$
1,3602008


6552009


1,5702010


1,3922011


1,167Thereafter


8,616Total long-term financing
    obligations, including current maturities

$
14,760    116




---



##### Table of Contents



Credit
    Facilities
  Available Capacity Under Credit Agreements.
  Credit Agreement Restructuring.
    Unsecured Revolving Credit Facility.
  EPEP Revolving Credit Facility.
  Contingent Letter of Credit Facility.
 117




---



##### Table of Contents



Restrictive
    Covenants
  $1.75 billion Revolving Credit
    Facility.
  (a)
    Our ratio of Debt to Consolidated EBITDA, each as defined in the
    credit agreement, shall not exceed 5.75 to 1 at anytime prior to
    June 30, 2007. Thereafter it shall not exceed 5.5 to 1
    until June 29, 2008 and 5.25 to 1 from June 30, 2008
    until maturity;  (b)
    Our ratio of Consolidated EBITDA, as defined in the credit
    agreement, to interest expense plus dividends paid shall not be
    less than 1.75 to 1 at anytime prior to December 31, 2006.
    Thereafter it shall not be less than 1.80 to 1 until
    June 29, 2008, and 2.00 to 1 from June 30, 2008 until
    maturity;  (c)
    EPNG, TGP and CIG cannot incur incremental Debt if the
    incurrence of this incremental Debt would cause their Debt to
    Consolidated EBITDA ratio, each as defined in the credit
    agreement, for that particular company to exceed 5.0 to 1; and  (d)
    the occurrence of an event of default and after the expiration
    of any applicable grace period, with respect to Debt in an
    aggregate principal amount of $200 million or more.  EPEP Revolving Credit Facility.
  Other Restrictions and Provisions. and/or
    Other
    Financing Arrangements
  Capital Trusts.
   118




---



##### Table of Contents



Non-Recourse Project Financings. and/or
  Letters of Credit.
  13.
    Commitments
    and Contingencies  Legal
    Proceedings
  Shareholder Litigation.
  ERISA Class Action Suits. William H.
    Lewis, III v. El Paso Corporation,
    et al. co-pay
  Cash Balance Plan Lawsuit. Tomlinson,
    et al. v. El Paso Corporation and
    El Paso Corporation Pension Plan
  Retiree Medical Benefits Matters. Yolton
    et al. v. El Paso Tennessee Pipeline Co. and Case
    Corporation.
 119




---



##### Table of Contents



Natural Gas Commodities Litigation.
  In re
    Western States Wholesale Natural Gas Antitrust
    Litigation Leggett et al. v. Duke Energy
    Corporation et al. Ever-Bloom Inc. v. AEP
    Energy Services Inc. et al. Farmland
    Industries, Inc. v. Oneok Inc. Learjet, Inc. v.
    Oneok Inc. Breckenridge, et al v.
    Oneok Inc., et al. Missouri Public Service
    Commission v. El Paso Corporation et al Arandell,
    et al v. Xcel Energy, et al Leggett Farmland Arandell Missouri Public Service
  Gas Measurement Cases. and/or In re: Natural Gas Royalties Qui Tam Litigation,
  Will Price, et al. v. Gas Pipelines and
    Their Predecessors, et al.,
  MTBE.
 120




---



##### Table of Contents



Government
    Investigations and Inquiries
  Reserve Revisions.
  Iraq Oil Sales.
  Other Government Investigations.
  Other
    Contingencies
  EPNG Rate Case.
  Iraq Imports.
  Navajo Nation.
 121




---



##### Table of Contents



and/or
  Environmental
    Matters
      December 31, 2006Sites

Expected


High(In millions)Operating

$
28


$
35Non-operating


252



439Superfund


34



58Total

$
314


$
532   
  Balance as of January 1, 2006

$
348Additions/adjustments for
    remediation activities


30Payments for remediation activities


(64
)Balance as of December 31,
    2006

$
314  122




---



##### Table of Contents



clean-up
  CERCLA Matters. clean-up
    Commitments,
    Purchase Obligations and Other Matters
  Operating Leases.
  Year Ending December 31,

Operating Leases(In millions)2007

$
662008


102009


72010


32011


1Thereafter


11Total

$
98     Guarantees.
 123




---



##### Table of Contents



Retiree
    Medical Benefits Matters
  Other Commercial Commitments.
  right-of-way right-of-way Navajo Nation
  14.
    Retirement
    Benefits  Overview
    of Retirement Benefits
  Pension Benefits.
      Retirement Savings Plan.
 124




---



##### Table of Contents



Other Postretirement Benefits.
  Pension and Other Postretirement Benefits.
    OtherPension Benefits


Postretirement Benefits2006


2005


2006


2005(In millions)Projected benefit
    obligation/accumulated postretirement benefit obligation

$
2,157


$
2,235


$
494


$
527Fair value of plan assets


2,382



2,350



276



251Current benefit liability


5







25



35Non-current benefit liability


52



77



228



215Non-current benefit asset


285



918



44



Accumulated other comprehensive
    income (loss), net of income taxes


(450
)


(49
)


15



          125




---



##### Table of Contents



Change in Benefit Obligation, Plan Assets and Funded
    Status.
  OtherPostretirementPension Benefits


Benefits2006


2005


2006


2005(In millions)Change in benefit
    obligation(1):Benefit obligation 
    beginning of period

$
2,235


$
2,118


$
527


$
541Service cost


17



22



11



1Interest cost


118



121



26



29Participant contributions










34



34Actuarial loss (gain)


(37
)


178
(2)


(35
)


(5
)Benefits paid


(176
)


(203
)


(69
)


(73
)Other






(1
)






Benefit obligation  end
    of period

$
2,157


$
2,235


$
494


$
527Change in plan assets:Fair value of plan assets at
    beginning of period

$
2,350


$
2,289


$
251


$
220Actual return on plan
    assets(3)


192



255



19



20Employer contributions


16



9



41



50Participant contributions










34



34Benefits paid


(176
)


(203
)


(69
)


(73
)Administrative expenses














Fair value of plan assets at end
    of period

$
2,382


$
2,350


$
276


$
251Reconciliation of funded status:Fair value of plan assets at
    September 30

$
2,382


$
2,350


$
276


$
251Less: Benefit
    obligation  end of period


2,157



2,235



494



527Funded status at September 30


225



115



(218
)


(276
)Fourth quarter contributions and
    income


3



2



9



11Unrecognized net actuarial
    loss(4)






733







20Unrecognized prior service
    cost(4)






(9
)






(5
)Net asset (liability) at
    December 31

$
228


$
841


$
(209
)

$
(250
)     (1)
    
    Benefit obligation in the table
    above refers to the projected benefit obligation for our pension
    plans and accumulated postretirement benefit obligation for our
    postretirement plans.(2)
    
    Increase is due primarily to
    changes in our discount rate and mortality assumptions in 2005.(3)
    
    We defer the difference between our
    actual return on plan assets and our expected return over a
    three year period, after which they are considered for inclusion
    in net benefit expense or income. Our deferred actuarial gains
    and losses are recognized only to the extent that all of our
    remaining unrecognized actual gains and loses exceed the greater
    of 10 percent of our projected benefit obligations or
    market related value of plan assets.(4)
    
    Amounts were reclassified to
    accumulated other comprehensive income upon the adoption of
    SFAS No. 158 in 2006. 126




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##### Table of Contents



Expected Payment of Future Benefits.
  Year Ending




Other PostretirementDecember 31,

Pension Benefits


Benefits(1)(In millions)2007

$
168


$
482008


168



472009


166



452010


166



442011


165



432012-2016


802



193Total

$
1,635


$
420     (1)
    
    Includes a reduction in each of the
    years presented for an expected subsidy related to the Medicare
    Prescription Drug, Improvement and Modernization Act of 2003.  Components of Net Benefit Cost.
  Pension Benefits


Other Postretirement Benefits2006


2005


2004


2006


2005


2004(In millions)Service cost

$
17


$
22


$
31


$
11


$
1


$
1Interest cost


118



121



121



26



29



34Expected return on plan assets


(175
)


(168
)


(187
)


(14
)


(12
)


(11
)Amortization of net actuarial loss


55



69



47











4Amortization of transition
    obligation


















8



8Amortization of prior service
    cost(1)


(2
)


(2
)


(3
)


(1
)


(1
)


(1
)Settlements, curtailment, and
    special termination benefits










(4
)










Other






7







(2
)






Net benefit cost

$
13


$
49


$
5


$
20


$
25


$
35     (1)
    
    As permitted, the amortization of
    any prior service cost is determined using a straight-line
    amortization of the cost over the average remaining service
    period of employees expected to receive benefits under the plan. 127




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##### Table of Contents



Actuarial Assumptions and Sensitivity
    Analysis.
  OtherPension Benefits


Postretirement Benefits2006


2005


2004


2006


2005


2004(Percent)








(Percent)Assumptions related to benefit
    obligations at September 30:Discount rate


5.75



5.50







5.50



5.25Rate of compensation increase


4.00



4.00Assumptions related to benefit
    costs for the year ended December 31:Discount rate


5.50



5.75



6.00



5.25



5.75



6.00Expected return on plan
    assets(1)


8.00



8.00



8.50



8.00



7.50



7.50Rate of compensation increase


4.00



4.00



4.00     (1)
    
    The expected return on plan assets
    is a pre-tax rate (before a tax rate ranging from
    26 percent to 27 percent on other postretirement
    benefits) that is primarily based on an expected risk-free
    investment return, adjusted for historical risk premiums and
    specific risk adjustments associated with our debt and equity
    securities. These expected returns were then weighted based on
    our target asset allocations of our investment portfolio.    2006


2005(In millions)One percentage point increase:Aggregate of service cost and
    interest cost

$
1


$
1Accumulated postretirement benefit
    obligation


18



20One percentage point decrease:Aggregate of service cost and
    interest cost

$
(1
)

$
(1
)Accumulated postretirement benefit
    obligation


(15
)


(18
)   Plan Assets.
  Pension Plans


Other Postretirement PlansAsset Category

Target


Actual 2006


Actual 2005


Target


Actual 2006


Actual 2005(Percent)








(Percent)Equity
    securities(1)


60



66



65



65



63



61Debt securities


40



33



34



35



33



32Other






1



1







4



7Total


100



100



100



100



100



100     (1)
    
    During 2005, we liquidated all of
    the El Paso common stock included in plan assets.   128




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##### Table of Contents



Other Matters.
  15.
    Stockholders
    Equity  Common Stock.
  Convertible Perpetual Preferred Stock.
    Dividends.
  ConvertibleCommon Stock

Preferred Stock($0.16/share)

(4.99%/year)Amount paid in 2006

$108

$37Amount paid in January 2007

$ 27

$ 9Declared in 2007:Date of declaration

February 14, 2007

February 14, 2007Date payable

April 2, 2007

April 2, 2007Payable to shareholders on record

March 2, 2007

March 15, 2007   paid-in-capital
   129




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##### Table of Contents



Accumulated Other Comprehensive Income.
  2006


2005Cash flow hedges (see Note 8)

$
80


$
(294
)Pension and other postretirement
    benefits (see Note 14)


(435
)


(49
)Investments available for sale


12



15Currency translation adjustment






(4
)Total accumulated other
    comprehensive loss, net of income taxes

$
(343
)

$
(332
)   16.
    Stock-Based
    Compensation    Non-Qualified Stock Options.
  WeightedWeighted


AverageAverage


Remaining# Shares


Exercise


ContractualUnderlying


Price


Term


AggregateOptions


per Share


(In years)


Intrinsic Value(In millions)Outstanding at December 31,
    2005


28,083,485


$
37.12Granted


2,348,982


$
12.32Exercised


(716,630
)

$
7.77Forfeited or canceled


(1,054,935
)

$
11.23Expired


(4,525,460
)

$
43.47Outstanding at December 31,
    2006


24,135,442


$
35.52



4.95


$
53Vested at December 31, 2006
    or expected to vest in the future


23,806,801


$
35.87



4.91


$
52Exercisable at December 31,
    2006


17,562,622


$
45.00



3.71


$
20    130




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##### Table of Contents



Fair Value Assumptions.
  2006


2005


2004Expected Term in Years


6.0



4.8



5.4Expected Volatility


38
%


42
%


45
%Expected Dividends


1.3
%


1.5
%


2.1
%Risk-Free Interest Rate


4.9
%


3.7
%


3.7
%     Restricted Stock.
  Weighted AverageGrant Date Fair ValueNonvested Shares

# Shares


per ShareNonvested at December 31, 2005


3,916,030


$
10.83Granted


2,226,625


$
13.09Vested


(1,904,640
)

$
12.21Forfeited


(498,795
)

$
11.02Nonvested at December 31, 2006


3,739,220


$
11.44       Employee Stock Purchase Plan.
 131




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##### Table of Contents



17.
    Business
    Segment Information    Pipelines.
  Exploration and Production.
  Marketing.
  Power.
       132




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##### Table of Contents



2006


2005


2004(In millions)Segment EBIT

$
1,838


$
979


$
591Corporate and other


(88
)


(521
)


(217
)Interest and debt expense


(1,228
)


(1,286
)


(1,497
)Distributions on preferred
    interests of consolidated subsidiaries






(9
)


(25
)Income taxes


9



331



116Income (loss) from continuing
    operations

$
531


$
(506
)

$
(1,032
)     As of or for the Year Ended December 31, 2006SegmentExploration and








CorporatePipelines


Production


Marketing


Power


and
    Other(1)


Total(In millions)Revenue from external customersDomestic

$
2,331


$
645
(2)

$
1,012


$
4


$
116


$
4,108Foreign


10



32



131











173Intersegment revenue


61



1,177
(2)


(1,201
)


2



(39
)


Operation and maintenance


728



410



28



54



99



1,319Depreciation, depletion, and
    amortization


370



645



4



2



26



1,047Loss on long-lived assets


15











3







18Earnings from unconsolidated
    affiliates


90



10







45







145EBIT


1,187



640



(71
)


82



(88
)


1,750Discontinued operations, net of
    income taxes


118











(27
)


(147
)


(56
)Assets of continuing
    operations(3)Domestic


13,071



5,858



1,115







1,950



21,994Foreign(4)


34



404



28



618



50



1,134Capital expenditures and
    investments in and advances to unconsolidated affiliates,
    net(5)


1,023



1,113







(44
)


14



2,106Total investments in
    unconsolidated affiliates


757



729







221







1,707     (1)
    
    Includes eliminations of
    intercompany transactions. Our intersegment revenues, along with
    our intersegment operating expenses, were incurred in the normal
    course of business between our operating segments. We recorded
    an intersegment revenue elimination of $37 million and an
    operation and maintenance expense elimination of
    $13 million, which is included in the Corporate
    column, to remove intersegment transactions.(2)
    
    Revenues from external customers
    include gains and losses related to our hedging of price risk
    associated with our natural gas and oil production. Intersegment
    revenues represent sales to our Marketing segment, which is
    responsible for marketing our production.(3)
    
    Excludes assets of discontinued
    operations of $4,133 million (see Note 2).(4)
    
    Of total foreign assets,
    approximately $362 million relates to property, plant and
    equipment, and approximately $0.7 billion relates to
    investments in and advances to unconsolidated affiliates.(5)
    
    Amounts are net of third party
    reimbursements of our capital expenditures and returns of
    invested capital.  133




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##### Table of Contents



As of or for the Year Ended December 31, 2005SegmentsExploration and








Field


Corporate(1)Pipelines


Production


Marketing


Power


Services


and Other


Total(In millions)Revenue from external customersDomestic

$
2,094


$
466
(2)

$
411


$
71


$
96


$
85


$
3,223Foreign


7



54
(2)


3















64Intersegment revenue


70



1,267
(2)


(1,210
)


11



27



(93
)


72
(3)Operation and maintenance


737



383



54



89



27



571



1,861Depreciation, depletion, and
    amortization


343



612



4



2



3



42



1,006(Gain) loss on long-lived assets


35











33



10



(4
)


74Earnings (losses) from
    unconsolidated affiliates


100



19







(139
)


301







281EBIT


924



696



(837
)


(89
)


285



(521
)


458Discontinued operations, net of
    income taxes


154



9







(476
)


251



(34
)


(96
)Assets of continuing
    operations(4)Domestic


12,363



5,215



3,786



70



99



4,081



25,614Foreign(5)


26



355



33



1,106







57



1,577Capital expenditures, and
    investments in and advances to unconsolidated affiliates,
    net(6)


780



1,851







5



8



14



2,658Total investments in
    unconsolidated affiliates


734



761







670











2,165     (1)
    
    Includes eliminations of
    intercompany transactions. Our intersegment revenues, along with
    our intersegment operating expenses, were incurred in the normal
    course of business between our operating segments. We recorded
    an intersegment revenue elimination of $91 million and an
    operation and maintenance expense elimination of
    $2 million, which is included in the Corporate
    column, to remove intersegment transactions.(2)
    
    Revenues from external customers
    include gains and losses related to our hedging of price risk
    associated with our natural gas and oil production. Intersegment
    revenues represent sales to our Marketing segment, which is
    responsible for marketing our production.(3)
    
    Relates to intercompany activities
    between our continuing operations and our discontinued
    operations.(4)
    
    Excludes assets of discontinued
    operations of $4,649 million.(5)
    
    Of total foreign assets,
    approximately $324 million relates to property, plant and
    equipment and approximately $1.0 billion relates to
    investments in and advances to unconsolidated affiliates.(6)
    
    Amounts are net of third party
    reimbursements of our capital expenditures and returns of
    invested capital.  134




---



##### Table of Contents



As of or for the Year Ended December 31, 2004SegmentsExploration and








Field


Corporate(1)Pipelines


Production


Marketing


Power


Services


and Other


Total(In millions)Revenue from external customersDomestic

$
2,048


$
535
(2)

$
697


$
241


$
938


$
133


$
4,592Foreign


9



26
(2)


2



67







15



119Intersegment revenue


88



1,174
(2)


(1,207
)


94



159



(236
)


72
(3)Operation and maintenance


632



365



53



240



74



201



1,565Depreciation, depletion, and
    amortization


329



548



13



13



8



51



962(Gain) loss on long-lived assets


(1
)


8







569



507



(6
)


1,077Earnings (losses) from
    unconsolidated affiliates


106



4







(249
)


618







479EBIT


1,059



734



(539
)


(747
)


84



(217
)


374Discontinued operations, net of
    income taxes


128



(36
)






51



20



(78
)


85Assets of continuing
    operations(4)Domestic


11,851



3,714



2,372



982



518



4,439



23,876Foreign(5)


58



366



32



1,572







96



2,124Capital expenditures, and
    investments in and advances to unconsolidated affiliates,
    net(6)


895



728







26



(15
)


10



1,644Total investments in
    unconsolidated affiliates


708



6







1,225



305



6



2,250     (1)
    
    Includes eliminations of
    intercompany transactions. Our intersegment revenues, along with
    our intersegment operating expenses, were incurred in the normal
    course of business between our operating segments. We recorded
    an intersegment revenue elimination of $236 million and an
    operation and maintenance expense elimination of
    $25 million, which is included in the Corporate
    column, to remove intersegment transactions.(2)
    
    Revenues from external customers
    include gains and losses related to our hedging of price risk
    associated with our natural gas and oil production. Intersegment
    revenues represent sales to our Marketing segment, which is
    responsible for marketing our production.(3)
    
    Relates to intercompany activities
    between our continuing operations and our discontinued
    operations.(4)
    
    Excludes assets of discontinued
    operations of $5,398 million.(5)
    
    Of total foreign assets,
    approximately $435 million relates to property, plant and
    equipment and approximately $1.5 billion relates to
    investments in and advances to unconsolidated affiliates.(6)
    
    Amounts are net of third party
    reimbursements of our capital expenditures and returns of
    invested capital. 135




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##### Table of Contents



18.
    Investments
    in, Earnings from and Transactions with Unconsolidated
    Affiliates      Net Ownership





Earnings (Losses) fromInterest


Investment


Unconsolidated Affiliates2006


2005


2006


2005


2006


2005


2004(Percent)


(In millions)


(In millions)Domestic:Four
    Star(1)


43



43


$
723


$
754


$
10


$
19


$
Citrus


50



50



597



596



62



66



65Enterprise Products
    Partners(2)






















183



6GulfTerra Energy
    Partners(2)


























601Midland Cogeneration
    Venture(2)






44











13



(162
)


(171
)Javelina(2)






















121



15Other Domestic Investments


various



various



36



47



3



17



22Total domestic










1,356



1,397



88



244



538Foreign:Araucaria
    Power(2)






60







187



2







Bolivia to Brazil Pipeline


8



8



105



96



11



20



24San Fernando Pipeline


50



50



57



53



16



14



13Habibullah
    Power(3)(4)


50



50



17



16



1



(13
)


(46
)Manaus/Rio
    Negro(5)


100



100



96



114



17



19



Saba Power
    Company(3)


94



94















(7
)


(51
)Porto
    Velho(4)


50



50



(34
)


(32
)


2



(16
)


(6
)Korea Independent Energy
    Corporation(2)






















127



22EGE
    Itabo(2)






25







24



1



(58
)


1Other Foreign
    Investments(4)


various



various



110



310



7



(49
)


(16
)Total foreign










351



768



57



(37
)


(59
)Total investments in unconsolidated
    affiliates









$
1,707


$
2,165Total earnings from unconsolidated
    affiliates

















$
145


$
281


$
479     (1)
    
    Amortization of our purchase cost
    in excess of the underlying net assets of Four Star was
    $54 million and $20 million during 2006 and 2005. (2)
    
    We sold our interests in these
    investments.(3)
    
    We have received approval from our
    Board of Directors to sell our interest in these investments,
    substantially all of which are targeted to close in the first
    half of 2007. (4)
    
    As of December 31, 2006 and
    2005, we had outstanding advances and receivables of
    $413 million and $385 million related to our foreign
    investments of which $25 million and $37 million
    related to our investment in Habibullah Power, $350 million
    and $331 million relate to our investment in Porto Velho,
    and the remainder in our other foreign investments. We
    recognized interest income on these outstanding advances and
    receivables of approximately $46 million, $47 million
    and $44 million in 2006, 2005 and 2004. (5)
    
    We deconsolidated these 100% owned
    investments in January 2005 upon entering into an agreement that
    will transfer ownership of these plants to the power purchaser
    in January 2008.   136




---



##### Table of Contents



Investment or Group

2006


2005


2004(In millions)Midland Cogeneration
    Venture(1)

$
13


$
(162
)

$
(161
)Asia power investments


(8
)


(64
)


(182
)Central and South American power
    investments


1



(89
)


Domestic power plants










(44
)Enterprise/GulfTerra






183



507Javelina






111



KIECO






108



Other






4



4$
6


$
91


$
124     (1)
    
    Amounts represent an impairment of
    our investment in 2004, recording our proportionate share of
    losses from our investment in MCV in 2005 primarily based on
    MCVs impairment of the plant assets, and a gain on the
    sale in 2006.    Year Ended December 31,2006


2005


2004(In millions)Operating results data:Operating revenues

$
1,101


$
1,476


$
2,075Operating expenses


741



1,407



1,428Income (loss) from continuing
    operations


174



(163
)


343Net income
    (loss)(1)


174



(163
)


343Financial position
    data:(2)Current assets

$
441


$
942Non-current assets


2,408



3,423Short-term debt


82



242Other current liabilities


321



441Long-term debt


556



1,171Other non-current liabilities


592



632Minority interest






83Redeemable preferred stock






9Equity in net assets


1,298



1,787     (1)
    
    Includes net income of
    $20 million, $15 million and $7 million in 2006,
    2005 and 2004, related to our proportionate share of affiliates
    in which we hold greater than a 50 percent interest.  (2)
    
    Includes total assets of
    $417 million, and $485 million as of December 31,
    2006 and 2005 related to our proportionate share of affiliates
    in which we hold greater than a 50 percent interest.   137




---



##### Table of Contents



2006


2005


2004(In millions)Operating
    revenue(1)

$
64


$
114


$
194Other revenue 
    management
    fees(2)










3Cost of
    sales(2)


3



7



90Reimbursement for operating
    expenses(2)










93Other income


6



9



8Interest income


46



47



44     (1)
    
    Decrease primarily due to the sale
    of investments in our Power segment.(2)
    
    Decrease in activity during 2005 is
    due primarily to the sale of GulfTerra during 2004.  Accounts Receivable Sales Program. Accounting for
    Transfers and Servicing of Financial Assets and Extinguishments
    of Liabilities.
  Matters
    that Could Impact Our Investments
  International Power.
  Porto Velho ($315 million).
    Manaus / Rio Negro ($97 million).
  Asian and Central American power investments
    ($105 million).
  Domestic Power.
 138




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##### Table of Contents



mark-to-market
  Investment in Bolivia.
  Investment in Argentina.
  Citrus.
 Supplemental
    Selected Quarterly Financial Information (Unaudited)    Quarters EndedMarch 31


June 30


September 30


December 31


Total(In millions, except per common share amounts)2006Operating revenues

$
1,337


$
1,089


$
942


$
913


$
4,281Operating income


683



363



218



163



1,427Earnings from unconsolidated
    affiliates


29



37



55



24



145Income (loss) from continuing
    operations


301



134



111



(15
)


531Discontinued operations, net of
    income taxes


55



16



24



(151
)


(56
)Net income (loss)


356



150



135



(166
)


475Net income (loss) available to
    common stockholders


346



141



126



(175
)


438Basic earnings per common shareIncome (loss) from continuing
    operations


0.44



0.19



0.15



(0.03
)


0.73Net income (loss)


0.53



0.21



0.18



(0.25
)


0.65Diluted earnings per common shareIncome (loss) from continuing
    operations


0.42



0.19



0.15



(0.03
)


0.72Net income (loss)


0.49



0.21



0.18



(0.25
)


0.642005Operating revenues

$
882


$
1,036


$
627


$
814


$
3,359Operating income (loss)


127



335



(190
)


(333
)


(61
)Earnings (losses) from
    unconsolidated affiliates


173



(35
)






143



281Income (loss) from continuing
    operations


42



29



(275
)


(302
)


(506
)Discontinued operations, net of
    income taxes


64



(267
)


(37
)


144



(96
)Net income (loss)


106



(238
)


(312
)


(162
)


(606
)Net income (loss) available to
    common stockholders


106



(246
)


(321
)


(172
)


(633
)Basic and diluted earnings per
    common shareIncome (loss) from continuing
    operations


0.07



0.03



(0.44
)


(0.47
)


(0.82
)Net income (loss)


0.17



(0.38
)


(0.50
)


(0.26
)


(0.98
)  139




---



##### Table of Contents



December 31, 2006.
  September 30, 2006. Mark-to-market
  June 30, 2006.
  December 31, 2005.
  September 30, 2005.
  June 30, 2005.
  March 31, 2005.
 140




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##### Table of Contents



Supplemental
    Natural Gas and Oil Operations (Unaudited)    Capitalized Costs.
  BrazilUnited


andStates


Egypt(1)


Worldwide2006Natural gas and oil properties:Costs subject to amortization

$
15,582


$
460


$
16,042Costs not subject to amortization


333



77



41015,915



537



16,452Less accumulated depreciation,
    depletion and amortization


11,322



202



11,524Net capitalized costs

$
4,593


$
335


$
4,9282005Natural gas and oil properties:Costs subject to amortization

$
14,764


$
371


$
15,135Costs not subject to amortization


384



107



49115,148



478



15,626Less accumulated depreciation,
    depletion and amortization


10,955



183



11,138Net capitalized costs

$
4,193


$
295


$
4,488     (1)
    
    Capitalized costs for Egypt were
    $4 million as of December 31, 2006. 141




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##### Table of Contents



Total Costs Incurred.
  United


Brazil andStates


Egypt


Worldwide2006Property acquisition costsProved properties

$
2


$
2


$
4Unproved properties


34



1



35Exploration costs


323



53



376Development costs


738



40



778Costs expended


1,097



96



1,193Asset retirement obligation costs


3







3Total costs incurred

$
1,100


$
96


$
1,1962005Property acquisition costsProved properties

$
643


$
8


$
651Unproved properties


143



1



144Exploration costs


143



15



158Development costs


503



6



509Costs expended


1,432



30



1,462Asset retirement obligation costs


1







1Total costs incurred

$
1,433


$
30


$
1,463Unconsolidated investment in Four
    Star(1)

$
769


$



$
7692004Property acquisition costsProved properties

$
33


$
69


$
102Unproved properties


32



3



35Exploration costs


185



25



210Development costs


395



1



396Costs expended


645



98



743Asset retirement obligation costs


30



3



33Total costs incurred

$
675


$
101


$
776     (1)
    
    Amount 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.     142




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##### Table of Contents



Unevaluated Capitalized Costs.
    Cumulative


Costs Excluded


CumulativeBalance(1)


for Years
    Ended(1)


BalanceDecember 31,


December 31


December 31,2006


2006


2005


2004


2003United StatesAcquisition

$
280


$
39


$
182


$
24


$
35Exploration


52



36



3



1



12Development


1















1Total United States


333



75



185



25



48Brazil & EgyptAcquisition


5



1







1



3Exploration


72



51



10



10



1Development


















Total Brazil & Egypt


77



52



10



11



4Worldwide

$
410


$
127


$
195


$
36


$
52     (1)
    
    Includes capitalized interest of
    $24 million, $9 million and $1 million for the
    years ended December 31, 2006, 2005, and 2004.  Depreciation, Depletion, and Amortization
    Rates.
  Natural Gas and Oil Reserves.
    143




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##### Table of Contents



Oil and Condensate


NGLNatural Gas (in Bcf)


(in MBbls)


(in MBbls)


EquivalentUnited








United








United


VolumesStates


Brazil


Worldwide


States


Brazil


Worldwide


States


in BcfeConsolidatedJanuary 1, 2004


2,061







2,061



32,371



20,543



52,914



15,985



2,474Revisions of previous estimates


(172
)






(172
)


(999
)


252



(747
)


724



(172
)Extensions, discoveries and other


79



38



117



2,214



1,848



4,062



58



142Purchases of reserves in place


15



38



53







1,848



1,848







64Sales of reserves in place


(21
)






(21
)


(1,276
)






(1,276
)


(47
)


(29
)Production


(238
)


(7
)


(245
)


(4,979
)


(320
)


(5,299
)


(3,519
)


(298
)December 31, 2004


1,724



69



1,793



27,331



24,171



51,502



13,201



2,181Revisions of previous estimates


(43
)


(2
)


(45
)


260



7,927



8,187



1,148



11Extensions, discoveries and other


183



5



188



8,145



772



8,917



169



242Purchases of reserves in place


192







192



13,338







13,338



772



276Sales of reserves in place


(18
)






(18
)


(969
)






(969
)


(89
)


(24
)Production


(207
)


(16
)


(223
)


(4,877
)


(620
)


(5,497
)


(2,639
)


(271
)December 31, 2005


1,831



56



1,887



43,228



32,250



75,478



12,562



2,415Revisions of previous
    estimates(1)


8



(1
)


7



(1,514
)


(365
)


(1,879
)


(1,834
)


(15
)Extensions, discoveries and other


254



8



262



5,012



209



5,221



958



299Purchases of reserves in place


1







1



90







90



32



2Sales of reserves in place


(17
)






(17
)


(230
)






(230
)


(174
)


(20
)Production


(213
)


(7
)


(220
)


(5,907
)


(247
)


(6,154
)


(1,532
)


(266
)December 31, 2006


1,864



56



1,920



40,679



31,847



72,526



10,012



2,415Proved developed reservesDecember 31, 2004


1,287



54



1,341



19,641



2,613



22,254



11,943



1,546December 31, 2005


1,404



27



1,431



28,581



1,144



29,725



11,010



1,675December 31, 2006


1,469



23



1,492



29,616



824



30,440



8,665



1,727Unconsolidated investment in
    Four StarDecember 31, 2006Net proved developed and
    undeveloped reserves


167







167



2,947







2,947



6,209



222Proved developed reserves


139







139



2,874







2,874



5,095



187December 31, 2005Net proved developed and
    undeveloped reserves


193







193



3,349







3,349



6,668



253Proved developed reserves


158







158



3,266







3,266



5,399



210     (1)
    
    Includes downward reserve revisions
    of approximately 54 Bcfe related to price and positive
    reserve revisions of 39 Bcfe related to performance.   144




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##### Table of Contents



Results of Operations.
  BrazilUnited


andStates


Egypt


Worldwide2006Net RevenuesSales to external customers

$
608


$
41


$
649Affiliated sales


1,160



(9
)


1,151Total


1,768



32



1,800Cost of products and
    services(1)


(58
)






(58
)Production
    costs(2)


(318
)


(7
)


(325
)Depreciation, depletion and
    amortization


(611
)


(19
)


(630
)781



6



787Income tax expense


(281
)


(2
)


(283
)Results of operations from
    producing activities

$
500


$
4


$
504Equity earnings from
    unconsolidated investment in Four
    Star(3)

$
10


$



$
102005Net RevenuesSales to external customers

$
466


$
62


$
528Affiliated sales


1,268



(9
)


1,259Total


1,734



53



1,787Cost of products and
    services(1)


(47
)






(47
)Production
    costs(2)


(253
)


(8
)


(261
)Depreciation, depletion and
    amortization


(567
)


(45
)


(612
)867







867Income tax expense


(309
)






(309
)Results of operations from
    producing activities

$
558


$



$
558Equity earnings from
    unconsolidated investment in Four
    Star(3)

$
19


$



$
192004Net RevenuesSales to external customers

$
534


$
26


$
560Affiliated sales


1,175







1,175Total


1,709



26



1,735Cost of products and
    services(1)


(54
)






(54
)Production
    costs(2)


(210
)






(210
)Depreciation, depletion and
    amortization


(530
)


(18
)


(548
)915



8



923Income tax expense


(333
)


(3
)


(336
)Results of operations from
    producing activities

$
582


$
5


$
587     (1)
    
    Cost of products and services
    consists primarily of transportation costs.(2)
    
    Production cost includes lease
    operating costs and production related taxes, including ad
    valorem and severance taxes.(3)
    
    Acquired in August 2005. 145




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##### Table of Contents



Standardized Measure of Discounted Future Net Cash
    Flows.
  UnitedStates


Brazil


Worldwide2006Future cash
    inflows(1)

$
12,349


$
1,977


$
14,326Future production costs


(3,623
)


(431
)


(4,054
)Future development costs


(1,280
)


(506
)


(1,786
)Future income tax expenses


(1,089
)


(239
)


(1,328
)Future net cash flows


6,357



801



7,15810% annual discount for estimated
    timing of cash flows


(2,302
)


(377
)


(2,679
)Standardized measure of discounted
    future net cash flows

$
4,055


$
424


$
4,479Standardized measure of discounted
    future net cash flows, including effects of hedging activities

$
4,225


$
424


$
4,6492005Future cash
    inflows(1)

$
18,175


$
1,992


$
20,167Future production costs


(3,968
)


(453
)


(4,421
)Future development costs


(1,335
)


(309
)


(1,644
)Future income tax expenses


(3,160
)


(286
)


(3,446
)Future net cash flows


9,712



944



10,65610% annual discount for estimated
    timing of cash flows


(3,660
)


(381
)


(4,041
)Standardized measure of discounted
    future net cash flows

$
6,052


$
563


$
6,615Standardized measure of discounted
    future net cash flows, including effects of hedging activities

$
5,748


$
560


$
6,3082004Future cash
    inflows(1)

$
11,895


$
1,077


$
12,972Future production costs


(3,585
)


(135
)


(3,720
)Future development costs


(1,234
)


(274
)


(1,508
)Future income tax expenses


(1,184
)


(141
)


(1,325
)Future net cash flows


5,892



527



6,41910% annual discount for estimated
    timing of cash flows


(2,004
)


(219
)


(2,223
)Standardized measure of discounted
    future net cash flows

$
3,888


$
308


$
4,196Standardized measure of discounted
    future net cash flows, including effects of hedging activities

$
3,907


$
305


$
4,212Unconsolidated Investment in
    Four
    Star(2)Standardized measure of discounted
    future net cash flows2006

$
323


$



$
3232005

$
617






$
617     (1)
    
    United States excludes
    $219 million, ($502) million and ($1) million of
    future net cash inflows (outflows) attributable to hedging
    activities in the years 2006, 2005 and 2004. Brazil excludes
    $4 million and $5 million of future net cash outflows
    attributable to hedging activities in 2005 and 2004.(2)
    
    Four Star was acquired in August
    2005. 146




---



##### Table of Contents



Changes in Standardized Measure of Discounted Future Net Cash
    Flows.
  Years Ended
    December 31,(1)2006


2005


2004(In millions)Sales and transfers of natural gas
    and oil produced net of 
    production costs

$
(1,516
)

$
(1,477
)

$
(1,470
)Net changes in prices and
    production costs


(2,891
)


2,884



29Extensions, discoveries and
    improved recovery, less related costs


549



793



268Changes in estimated future
    development costs


(55
)


2



4Previously estimated development
    costs incurred during the period


192



247



156Revision of previous quantity
    estimates


(38
)


47



(453
)Accretion of discount


827



476



568Net change in income taxes


1,123



(1,093
)


257Purchases of reserves in place


4



956



114Sale of reserves in place


(42
)


(83
)


(75
)Change in production rates, timing
    and other


(289
)


(333
)


(94
)Net change

$
(2,136
)

$
2,419


$
(696
)     (1)
    
    This disclosure reflects changes in
    the standardized measure calculation excluding the effects of
    hedging activities. 147




---



##### Table of Contents



SCHEDULE II
    EL PASO CORPORATION
    VALUATION AND QUALIFYING ACCOUNTS
    Years Ended December 31, 2006, 2005 and 2004
    (In millions)  Balance at


Charged to





Charged


Balance atBeginning


Costs and





to Other


End ofDescription

of Period


Expenses


Deductions


Accounts


Period2006(1)Allowance for doubtful accounts

$
65


$
(5
)

$
(27
)(2)

$
(5
)

$
28Valuation allowance on deferred
    tax assets


107



62



(39
)


(3
)


127Legal reserves


574



48



(74
)






548Environmental reserves


348



30



(64
)






314Regulatory reserves


1



65



(1
)






652005(1)Allowance for doubtful accounts

$
195


$
(68
)

$
(54
)(2)

$
(8
)

$
65Valuation allowance on deferred
    tax assets


51



40
(3)


(5
)


21



107Legal reserves


592



496



(516
)(4)


2



574Environmental reserves


349



60



(61
)(4)






348Regulatory reserves


1















12004(1)Allowance for doubtful accounts

$
269


$
(48
)

$
(22
)(2)

$
(4
)

$
195Valuation allowance on deferred
    tax assets


9



46
(3)


(4
)






51Legal reserves


1,169



145



(655
)(4)


(67
)


592Environmental reserves


377



16



(46
)(4)


2



349Regulatory reserves


13







(12
)






1     (1)
    
    Amounts reflect the
    reclassification of discontinued operations.(2)
    
    In 2006, relates primarily to the
    sale of our accounts receivable under an accounts receivable
    sales program. In 2005 and 2004, relates primarily to accounts
    written off.(3)
    
    Relates primarily to valuation
    allowances for deferred tax assets related to the Western Energy
    Settlement, foreign ceiling test charges, foreign asset
    impairments and state and foreign net operating loss carryovers.(4)
    
    Relates primarily to payments for
    various litigation reserves (including $442 million and
    $602 million related to the Western Energy Settlement),
    environmental remediation reserves or revenue crediting and rate
    settlement reserves. 148




---



##### Table of Contents



ITEM 9.
    CHANGES
    IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
    FINANCIAL DISCLOSURE  Form 8-K Regulation S-K.
  ITEM 9A.
    CONTROLS
    AND PROCEDURES  Evaluation
    of Disclosure Controls and Procedures
  and/or
  Changes
    in Internal Control over Financial Reporting
    ITEM 9B.
    OTHER
    INFORMATION  Form 10-K Form 8-K.
 149




---



##### Table of Contents



PART III  ITEM 10.
    DIRECTORS,
    EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE  Form 10-K
    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, AND DIRECTOR
    INDEPENDENCE    ITEM 14.
    PRINCIPAL
    ACCOUNTANT FEES AND SERVICES   PART IV  ITEM 15.
    EXHIBITS AND
    FINANCIAL STATEMENT SCHEDULES  (a)
    The
    following documents are filed as a part of this
    report:   150




---



##### Table of Contents



PageReports of Independent Registered
    Public Accounting Firms


79Consolidated Statements of Income


84Consolidated Balance Sheets


85Consolidated Statements of Cash
    Flows


87Consolidated Statements of
    Stockholders Equity


88Consolidated Statements of
    Comprehensive Income


89Notes to Consolidated Financial
    Statements


902.


Financial statement schedules and
    supplementary information required to be submittedSchedule II 
    Valuation and Qualifying Accounts


1483.


Exhibits


154   Form 10-K Regulation S-K.
  Undertaking
  Regulation S-K,
 151




---



##### Table of Contents



SIGNATURES      By
    /s/  Douglas
    L. Foshee   President and Chief Executive
    Officer
    Signature

Title

Date/s/  Douglas
    L. FosheeDouglas
    L. Foshee

President, Chief Executive Officer
    
    and Director (Principal Executive Officer)

February 28, 2007/s/  D.
    Mark LelandD.
    Mark Leland

Executive Vice President and Chief
    
    Financial Officer (Principal Financial Officer)

February 28, 2007/s/  John
    R. SultJohn
    R. Sult

Senior Vice President and
    Controller (Principal Accounting Officer)

February 28, 2007/s/  Ronald
    L. Kuehn,
    Jr.Ronald
    L. Kuehn, Jr.

Chairman of the Board

February 28, 2007/s/  Juan
    Carlos
    BraniffJuan
    Carlos Braniff

Director

February 28, 2007/s/  James
    L. DunlapJames
    L. Dunlap

Director

February 28, 2007/s/  Robert
    W. GoldmanRobert
    W. Goldman

Director

February 28, 2007/s/  Anthony
    W. Hall,
    Jr.Anthony
    W. Hall, Jr.

Director

February 28, 2007/s/  Thomas
    R. HixThomas
    R. Hix

Director

February 28, 2007/s/  William
    H. JoyceWilliam
    H. Joyce

Director

February 28, 2007/s/  Ferrell
    P. McCleanFerrell
    P. McClean

Director

February 28, 2007 152




---



##### Table of Contents



Signature

Title

Date/s/  Steven
    J. ShapiroSteven
    J. Shapiro

Director

February 28, 2007/s/  J.
    Michael
    TalbertJ.
    Michael Talbert

Director

February 28, 2007/s/  Robert
    F. VagtRobert
    F. Vagt

Director

February 28, 2007/s/  John
    L. WhitmireJohn
    L. Whitmire

Director

February 28, 2007/s/  Joe
    B. WyattJoe
    B. Wyatt

Director

February 28, 2007  153




---



##### Table of Contents



EL PASO
    CORPORATION
  EXHIBIT INDEX
 December 31,
    2006
    ExhibitNumber

Description3
.A

Second Amended and Restated
    Certificate of Incorporation (included in Exhibit 3.A to
    our Current Report on
    Form 8-K
    filed May 31, 2005).3
.B

By-laws effective as of
    October 26, 2006 (Exhibit 3.B to our
    Form 8-K
    filed October 26, 2006).4
.A

Indenture dated as of May 10,
    1999, by and between El Paso and HSBC Bank USA, National
    Association (as
    successor-in-interest
    to JPMorgan Chase Bank (formerly The Chase Manhattan Bank)), as
    Trustee (Exhibit 4.A to our 2004
    Form 10-K).4
.B

Certificate of Designations of
    4.99% Convertible Perpetual Preferred Stock (included in
    Exhibit 3.A to our Current Report on
    Form 8-K
    filed May 31, 2005).4
.C

Registration Rights Agreement,
    dated April 15, 2005, by and among El Paso Corporation
    and the Initial Purchasers party thereto (Exhibit 4.A to
    our Current Report on
    Form 8-K
    filed April 15, 2005).4
.D

Tenth Supplemental Indenture dated
    as of December 28, 2005 between El Paso Corporation
    and HSBC Bank USA, National Association, as trustee
    (Exhibit 4.A to our
    Form 8-K
    filed January 4, 2006).4
.E

Eleventh Supplemental Indenture
    dated as of August 31, 2006, between El Paso
    Corporation and HSBC Bank USA, National Association, as trustee
    (Exhibit 4.A to our 2006 Third Quarter
    Form 10-Q).+10
.A

1995 Compensation Plan for
    Non-Employee Directors Amended and Restated effective as of
    December 4, 2003 (Exhibit 10.F to our 2003
    Form 10-K).+10
.B

Stock Option Plan for Non-Employee
    Directors Amended and Restated effective as of January 20,
    1999 (Exhibit 10.G to our 2004
    Form 10-K);
    Amendment No. 1 effective as of July 16, 1999 to the
    Stock Option Plan for Non-Employee Directors
    (Exhibit 10.G.1 to our 2004
    Form 10-K);
    Amendment No. 2 effective as of February 7, 2001 to
    the Stock Option Plan for Non-Employee Directors
    (Exhibit 10.F.1 to our 2001 First Quarter
    Form 10-Q);
    Amendment No. 3 effective as of October 26, 2006 to
    the Stock Option Plan for Non-Employee Directors
    (Exhibit 10.N to our 2006 Third Quarter
    Form 10-Q).+10
.C

2001 Stock Option Plan for
    Non-Employee Directors effective as of January 29, 2001
    (Exhibit 10.1 to our
    Form S-8
    filed June 29, 2001); Amendment No. 1 effective as of
    February 7, 2001 to the 2001 Stock Option Plan for
    Non-Employee Directors (Exhibit 10.G.1 to our 2001
    Form 10-K);
    Amendment No. 2 effective as of December 4, 2003 to the
    2001 Stock Option Plan for Non-Employee Directors
    (Exhibit 10.H.1 to our 2003
    Form 10-K);
    Amendment No. 3 effective as of October 26, 2006 to
    the 2001 Stock Option Plan for Non-Employee Directors
    (Exhibit 10.O to our 2006 Third Quarter
    Form 10-Q).+10
.D

1995 Omnibus Compensation Plan
    Amended and Restated effective as of August 1, 1998
    (Exhibit 10.I to our 2004
    Form 10-K);
    Amendment No. 1 effective as of December 3, 1998 to
    the 1995 Omnibus Compensation Plan (Exhibit 10.I.1 to our
    2004
    Form 10-K);
    Amendment No. 2 effective as of January 20, 1999 to
    the 1995 Omnibus Compensation Plan (Exhibit 10.I.2 to our
    2004
    Form 10-K);
    Amendment No. 3 effective as of October 26, 2006 to
    the 1995 Omnibus Compensation Plan; (Exhibit 10.L to our
    2006 Third Quarter
    Form 10-Q).+10
.E

1999 Omnibus Incentive
    Compensation Plan dated January 20, 1999 (Exhibit 10.1
    to our
    Form S-8
    filed May 20, 1999); Amendment No. 1 effective as of
    February 7, 2001 to the 1999 Omnibus Incentive Compensation
    Plan (Exhibit 10.V.1 to our 2001 First Quarter
    Form 10-Q);
    Amendment No. 2 effective as of May 1, 2003 to the 1999
    Omnibus Incentive Compensation Plan (Exhibit 10.I.1 to our
    2003 Second Quarter
    Form 10-Q);
    Amendment No. 3 effective as of October 26, 2006 to
    the 1999 Omnibus Incentive Compensation Plan (Exhibit 10.K
    to our 2006 Third Quarter
    Form 10-Q). 154




---



##### Table of Contents



ExhibitNumber

Description+10
.F

2001 Omnibus Incentive
    Compensation Plan effective as of January 29, 2001
    (Exhibit 10.1 to our
    Form S-8
    filed June 29, 2001); Amendment No. 1 effective as of
    February 7, 2001 to the 2001 Omnibus Incentive Compensation
    Plan (Exhibit 10.J.1 to our 2001
    Form 10-K);
    Amendment No. 2 effective as of April 1, 2001 to the 2001
    Omnibus Incentive Compensation Plan (Exhibit 10.J.1 to our
    2002
    Form 10-K);
    Amendment No. 3 effective as of July 17, 2002 to the
    2001 Omnibus Incentive Compensation Plan (Exhibit 10.J.1 to
    our 2002 Second Quarter
    Form 10-Q);
    Amendment No. 4 effective as of May 1, 2003 to the
    2001 Omnibus Incentive Compensation Plan (Exhibit 10.J.1 to
    our 2003 Second Quarter
    Form 10-Q);
    Amendment No. 5 effective as of March 8, 2004 to the
    2001 Omnibus Incentive Compensation Plan (Exhibit 10.K.1 to our
    2003
    Form 10-K);
    Amendment No. 6 effective as of October 26, 2006 to
    the 2001 Omnibus Incentive Compensation Plan (Exhibit 10.M
    to our 2006 Third Quarter
    Form 10-Q).+10
.G

Supplemental Benefits Plan Amended
    and Restated effective December 7, 2001 (Exhibit 10.K
    to our 2001
    Form 10-K);
    Amendment No. 1 effective as of November 7, 2002 to
    the Supplemental Benefits Plan (Exhibit 10.K.1 to our 2002
    Form 10-K);
    Amendment No. 2 effective as of June 1, 2004 to the
    Supplemental Benefits Plan (Exhibit 10.L.1 to our 2004
    Form 10-K);
    Amendment No. 3 effective December 17, 2004 to the
    Supplemental Benefits Plan (Exhibit 10.UU to our 2004 Third
    Quarter
    Form 10-Q);
    Amendment No. 4 to the Supplemental Benefits Plan effective
    as of December 31, 2004 (Exhibit 10.I.1 to our 2005
    Form 10-K).+10
.H

Senior Executive Survivor Benefit
    Plan Amended and Restated effective as of August 1, 1998
    (Exhibit 10.M to our 2004
    Form 10-K);
    Amendment No. 1 effective as of February 7, 2001 to
    the Senior Executive Survivor Benefit Plan (Exhibit 10.I.1
    to our 2001 First Quarter
    Form 10-Q);
    Amendment No. 2 effective as of October 1, 2002 to the
    Senior Executive Survivor Benefit Plan (Exhibit 10.L.1 to
    our 2002
    Form 10-K).+10
.I

Key Executive Severance Protection
    Plan Amended and Restated effective as of August 1, 1998
    (Exhibit 10.N to our 2004
    Form 10-K);
    Amendment No. 1 effective as of February 7, 2001 to
    the Key Executive Severance Protection Plan (Exhibit 10.K.1
    to our 2001 First Quarter
    Form 10-Q);
    Amendment No. 2 effective as of November 7, 2002 to
    the Key Executive Severance Protection Plan (Exhibit 10.N.1
    to our 2002
    Form 10-K);
    Amendment No. 3 effective as of December 6, 2002 to
    the Key Executive Severance Protection Plan (Exhibit 10.N.1
    to our 2002
    Form 10-K);
    Amendment No. 4 effective as of September 2, 2003 to
    the Key Executive Severance Protection Plan (Exhibit 10.N.1
    to our 2003 Third Quarter
    Form 10-Q).+10
.J

2004 Key Executive Severance
    Protection Plan effective as of March 9, 2004
    (Exhibit 10.P to our 2003
    Form 10-K).+10
.K

Director Charitable Award Plan
    Amended and Restated effective as of August 1, 1998
    (Exhibit 10.P to our 2004
    Form 10-K);
    Amendment No. 1 effective as of February 7, 2001 to
    the Director Charitable Award Plan (Exhibit 10.L.1 to our
    2001 First Quarter
    Form 10-Q);
    Amendment No. 2 effective as of December 4, 2003 to
    the Director Charitable Award Plan (Exhibit 10.Q.1 to our
    2003
    Form 10-K).+10
.L

Strategic Stock Plan Amended and
    Restated effective as of December 3, 1999
    (Exhibit 10.1 to our
    Form S-8
    filed January 14, 2000); Amendment No. 1 effective as
    of February 7, 2001 to the Strategic Stock Plan
    (Exhibit 10.M.1 to our 2001 First Quarter
    Form 10-Q);
    Amendment No. 2 effective as of November 7, 2002 to the
    Strategic Stock Plan; Amendment No. 3 effective as of
    December 6, 2002 to the Strategic Stock Plan and Amendment
    No. 4 effective as of January 29, 2003 to the
    Strategic Stock Plan (Exhibit 10.P.1 to our 2002
    Form 10-K);
    Amendment No. 5 effective as of October 26, 2006 to
    the Strategic Stock Plan (Exhibit 10.J to our 2006 Third
    Quarter
    Form 10-Q).+10
.M

Domestic Relocation Policy
    effective November 1, 1996 (Exhibit 10.R to our 2004
    Form 10-K).+10
.N

Executive Award Plan of Sonat Inc.
    Amended and Restated effective as of July 23, 1998, as
    amended May 27, 1999 (Exhibit 10.S to our 2004
    Form 10-K);
    Termination of the Executive Award Plan of Sonat Inc.
    (Exhibit 10.K.1 to our 2000 Second Quarter
    Form 10-Q);
    Amendment to the Executive Award Plan of Sonat Inc. effective as
    of October 26, 2006 (Exhibit 10.H to our 2006 Third
    Quarter
    Form 10-Q). 155




---



##### Table of Contents



ExhibitNumber

Description+10
.O

Omnibus Plan for Management
    Employees Amended and Restated effective as of December 3,
    1999 (Exhibit 10.1 to our
    Form S-8
    filed December 18, 2000); Amendment No. 1 effective as
    of December 1, 2000 to the Omnibus Plan for Management
    Employees (Exhibit 10.1 to our
    Form S-8
    filed December 18, 2000); Amendment No. 2 effective as
    of February 7, 2001 to the Omnibus Plan for Management
    Employees (Exhibit 10.U.1 to our 2001 First Quarter
    Form 10-Q);
    Amendment No. 3 effective as of December 7, 2001 to
    the Omnibus Plan for Management Employees (Exhibit 10.1 to
    our
    Form S-8
    filed February 11, 2002); Amendment No. 4 effective as
    of December 6, 2002 to the Omnibus Plan for Management
    Employees (Exhibit 10.T.1 to our 2002
    Form 10-K);
    Amendment No. 5 effective as of October 26, 2006 to
    the Corporation Omnibus Plan for Management Employees
    (Exhibit 10.I to our 2006 Third Quarter
    Form 10-Q).+10
.P

Severance Pay Plan Amended and
    Restated effective as of October 1, 2002; Supplement
    No. 1 to the Severance Pay Plan effective as of
    January 1, 2003; and Amendment No. 1 to Supplement
    No. 1 effective as of March 21, 2003
    (Exhibit 10.Z to our 2003 First Quarter
    Form 10-Q);
    Amendment No. 2 to Supplement No. 1 effective as of
    June 1, 2003 (Exhibit 10.Z.1 to our 2003 Second Quarter
    Form 10-Q);
    Amendment No. 3 to Supplement No. 1 effective as of
    September 2, 2003 (Exhibit 10.Z.1 to our 2003 Third
    Quarter
    Form 10-Q);
    Amendment No. 4 to Supplement No. 1 effective as of
    October 1, 2003 (Exhibit 10.W.1 to our 2003
    Form 10-K);
    Amendment No. 5 to Supplement No. 1 effective as of
    February 2, 2004 (Exhibit 10.W.1 to our 2003
    Form 10-K);
    Supplement No. 2 dated April 1, 2005 to the Severance
    Pay Plan Amended and Restated effective as of October 1,
    2002 (Exhibit 10.S.1 to our 2005
    Form 10-K).+10
.Q

Letter Agreement dated
    September 20, 2006 between El Paso Corporation and
    Brent J. Smolik (Exhibit 10.A to our
    Form 8-K
    filed October 16, 2006).+10
.R

Letter Agreement dated
    July 15, 2003 between El Paso and Douglas L. Foshee
    (Exhibit 10.U to our 2003 Third Quarter
    Form 10-Q).+10
.S

Letter Agreement dated
    December 18, 2003 between El Paso and Douglas L.
    Foshee (Exhibit 10.BB.1 to our 2003
    Form 10-K).+10
.T

Form of Indemnification Agreement
    of each member of the Board of Directors effective
    November 7, 2002 or the effective date such director was
    elected to the Board of Directors, whichever is later
    (Exhibit 10.FF to our 2002
    Form 10-K).+10
.U

Form of Indemnification Agreement
    executed by El Paso for the benefit of each officer and
    effective the date listed in Schedule A thereto
    (Exhibit 10.F to our 2006 Third Quarter
    Form 10-Q).+10
.V

Indemnification Agreement executed
    by El Paso for the benefit of Douglas L. Foshee, effective
    December 17, 2004 (Exhibit 10.XX to our 2004 Third
    Quarter
    Form 10-Q).10
.W

Agreement With Respect to
    Collateral dated as of June 11, 2004, by and among
    El Paso Production Oil & Gas USA, L.P., a Delaware
    limited partnership, Bank of America, N.A., acting solely in its
    capacity as Collateral Agent under the Collateral Agency
    Agreement, and The Office of the Attorney General of the State
    of California, acting solely in its capacity as the Designated
    Representative under the Designated Representative Agreement
    (Exhibit 10.HH to our 2003
    Form 10-K).10
.X

Purchase Agreement dated
    April 11, 2005, by and among El Paso Corporation and
    the Initial Purchasers party thereto (Exhibit 10.A to our
    Form 8-K
    filed April 15, 2005).+10
.Y

El Paso Corporation 2005
    Compensation Plan for Non-Employee Directors (Exhibit 10.A
    to our
    Form 8-K
    filed May 31, 2005); Amendment No. 1 to the
    El Paso Corporation 2005 Compensation Plan for Non-Employee
    Directors effective as of October 26, 2006
    (Exhibit 10.P to our 2006 Third Quarter
    Form 10-Q).+10
.Z

El Paso Corporation 2005
    Omnibus Incentive Compensation Plan (Exhibit 10.B to our
    Form 8-K
    filed May 31, 2005); Amendment No. 1 to the 2005
    Omnibus Incentive Compensation Plan effective as of
    December 2, 2005 (Exhibit 10.HH.1 to our 2005
    Form 10-K);
    Amendment No. 2 to the El Paso Corporation 2005
    Omnibus Incentive Compensation Plan effective as of
    October 26, 2006 (Exhibit 10.Q to our 2006 Third
    Quarter
    Form 10-Q).+10
.AA

El Paso Corporation Employee
    Stock Purchase Plan, Amended and Restated Effective as of
    July 1, 2005 (Exhibit 10.E to our 2005 Second Quarter
    Form 10-Q);
    Amendment No. 1 to the El Paso Corporation Employee
    Stock Purchase Plan effective as of October 26, 2006
    (Exhibit 10.G to our 2006 Third Quarter
    Form 10-Q). 156




---



##### Table of Contents



ExhibitNumber

Description+10
.BB

2005 Supplemental Benefits Plan
    effective as of January 1, 2005 (Exhibit 10.KK to our
    2005
    Form 10-K).10
.CC

Credit Agreement among
    El Paso Corporation and El Paso Production
    Oil & Gas USA, L.P., as Borrowers, Fortis Capital
    Corp., as Administrative Agent, Arranger and Bookrunner, dated
    as of November 3, 2005 (Exhibit 10.A to our
    Form 8-K
    filed November 4, 2005); First Amendment, Consent and
    Waiver Agreement, dated as of December 20, 2005, among
    El Paso Corporation and El Paso Production
    Oil & Gas USA, L.P., as Borrowers, Fortis Capital
    Corp., as Administrative Agent for the Lenders, and the several
    Lenders party from time to time thereto (Exhibit 10.B to
    our
    Form 8-K
    filed January 4, 2006).10
.DD

Amended and Restated Credit
    Agreement dated as of July 31, 2006, among El Paso
    Corporation, Colorado Interstate Gas Company, El Paso
    Natural Gas Company, Tennessee Gas Pipeline Company, several
    banks and other financial institutions from time to time parties
    thereto and JPMorgan Chase Bank, N.A., as administrative agent
    and as collateral agent. (Exhibit 10.A to our
    Form 8-K
    filed August 2, 2006).10
.EE

Amended and Restated Security
    Agreement dated as of July 31, 2006, made by El Paso
    Corporation, Colorado Interstate Gas Company, El Paso
    Natural Gas Company, Tennessee Gas Pipeline Company, the
    Subsidiary Grantors and certain other credit parties thereto and
    JPMorgan Chase Bank, N.A., not in its individual capacity, but
    solely as collateral agent for the Secured Parties and as the
    depository bank. (Exhibit 10.B to our
    Form 8-K
    filed August 2, 2006).*10
.EE.1

Amendment No. 1 dated as of
    January 19, 2007 to the Amended and Restated Credit
    Agreement dated as of July 31, 2006 among El Paso
    Corporation, Colorado Interstate Gas Company, El Paso Natural
    Gas Company, Tennessee Gas Pipeline Company, the several banks
    and other financial institutions from time to time parties
    thereto, and JPMorgan Chase Bank, N.A., as administrative agent
    and as collateral agent.10
.FF

Amended and Restated Parent
    Guarantee Agreement dated as of July 31, 2006, made by
    El Paso Corporation, in favor of JPMorgan Chase Bank, N.A.,
    as Collateral Agent. (Exhibit 10.C to our
    Form 8-K
    filed August 2, 2006).10
.GG

Amended and Restated Subsidiary
    Guarantee Agreement dated as of July 31, 2006, made by each
    of the Subsidiary Guarantors in favor of JPMorgan Chase Bank,
    N.A., as Collateral Agent. (Exhibit 10.D to our
    Form 8-K
    filed August 2, 2006).10
.HH

Credit Agreement dated as of
    July 19, 2006 among El Paso Corporation, as Borrower,
    Deutsche Bank AG New York Branch, as Initial Lender, Issuing
    Bank, Administrative Agent and Collateral Agent
    (Exhibit 10.A to our
    Form 8-K
    filed July 20, 2006).10
.II

Purchase and Sale Agreement dated
    December 22, 2006, among El Paso Corporation,
    El Paso CNG Company, L.L.C., and TransCanada American
    Investments Ltd. (Exhibit 10.A to our
    Form 8-K
    filed December 29, 2006).10
.JJ

Purchase and Sale Agreement dated
    December 22, 2006, among El Paso Great Lakes Company,
    L.L.C., TC GL Intermediate Limited Partnership and TransCanada
    PipeLine USA Ltd. (Exhibit 10. B to our
    Form 8-K
    filed December 29, 2006).*12


Ratio of Earnings to Combined
    Fixed Charges and Preferred Stock Dividends.*21


Subsidiaries of El Paso
    Corporation.*23
.A

Consent of Independent Registered
    Public Accounting Firm Ernst & Young LLP.*23
.B

Consent of Independent Registered
    Public Accounting Firm, PricewaterhouseCoopers, LLP.*23
.C

Consent of Ryder Scott Company,
    L.P.*31
.A

Certification of Chief Executive
    Officer pursuant to Section 302 of the Sarbanes-Oxley Act
    of 2002*31
.B

Certification of Chief Financial
    Officer pursuant to Section 302 of the Sarbanes-Oxley Act
    of 2002*32
.A

Certification of Chief Executive
    Officer pursuant to Section 906 of the Sarbanes-Oxley Act
    of 2002*32
.B

Certification of Chief Financial
    Officer pursuant to Section 906 of the Sarbanes-Oxley Act
    of 2002*99
.A

Ryder Scott reserve report for El
    Paso Exploration & Production Company as of
    December 31, 2006.*99
.B

Ryder Scott reserve report for
    Four Star Oil & Gas Company as of December 31, 2006.  157