##### 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 1934
 For the fiscal year ended December 31, 2007
 OR
 o
    
    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the transition period from          to          .
 Commission File Number 1-14365
 El Paso Corporation
  Delaware
(State or Other Jurisdiction of 
Incorporation or Organization)
    
    76-0568816
(I.R.S. Employer
Identification No.)El Paso Building 
1001 Louisiana Street 
Houston, Texas
(Address of Principal Executive Offices)
    
    77002
(Zip Code)
 Telephone Number: (713) 420-2600
Internet Website: www.elpaso.com
Securities registered pursuant to Section 12(b) of the Act:
 Title of Each Class
    
    Name of Each Exchange
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
 o
  Large accelerated filer þ
    
    Accelerated filer o
    
    Non-accelerated filer o
    
    Smaller reporting company o(Do not check if a smaller reporting company)
 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




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##### 



EL PASO CORPORATION
TABLE OF CONTENTS
 Caption
    
    PagePART IItem 1.
    
    Business
    
    4Item 1A.
    
    Risk Factors
    
    27Item 1B.
    
    Unresolved Staff Comments
    
    37Item 2.
    
    Properties
    
    37Item 3.
    
    Legal Proceedings
    
    37Item 4.
    
    Submission of Matters to a Vote of Security Holders
    
    37PART IIItem 5.
    
    Market for Registrants Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
    
    38Item 6.
    
    Selected Financial Data
    
    40Item 7.
    
    Managements Discussion and Analysis of Financial Condition and Results of Operations
    
    41Item 7A.
    
    Quantitative and Qualitative Disclosures About Market Risk
    
    76Item 8.
    
    Financial Statements and Supplementary Data
    
    79Item 9.
    
    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
    
    143Item 9A.
    
    Controls and Procedures
    
    143Item 9B.
    
    Other Information
    
    143PART IIIItem 10.
    
    Directors, Executive Officers and Corporate Governance
    
    144Item 11.
    
    Executive Compensation
    
    144Item 12.
    
    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
    
    144Item 13.
    
    Certain Relationships and Related Transactions, and Director Independence
    
    144Item 14.
    
    Principal Accountant Fees and Services
    
    144PART IVItem 15.
    
    Exhibits and Financial Statement Schedules
    
    145Signatures
    
    146Amendment No.1 to 1995 Compensation Plan for Non-Employee DirectorsAmendment No.2 to Stock Option Plan for Non-Employee DirectorsAmendment No.1 to 2001 Stock Option Plan for Non-Employee DirectorsAmendment No.2 to 2001 Stock Option Plan for Non-Employee Directors1999 Omnibus Incentive Compensation PlanAmendment No.1 to 2001 to the 1999 Omnibus Incentive Compensation Plan2001 Omnibus Incentive Compensation PlanAmendment No.1 to to the 2001 Omnibus Incentive Compensation PlanAmendment No.2 to to the 2001 Omnibus Incentive Compensation PlanAmendment No.3 to to the 2001 Omnibus Incentive Compensation PlanAmended Supplemental Benefits PlanAmendment No.1 to Supplemental Benefits PlanAmendment No.5 to Amended Supplemental Benefits PlanAmendment No.1 to Senior Executive Survivor Benefit PlanAmendment No.2 to Senior Executive Survivor Benefit PlanAmendment No.1 to Key Executive Severance Protection PlanAmendment No.2 to Key Executive Severance Protection PlanAmendment No.3 to Key Executive Severance Protection PlanAmendment No.5 to Key Executive Severance Protection Plan, as amendedAmendment No.1 to 2004 Key Executive Severance Protection PlanAmendment No.1 to Director Charitable Award PlanAmended Strategic Stock PlanAmendment No.1 to Strategic Stock PlanAmendment No.2 to Strategic Stock PlanAmendment No.3 to Strategic Stock PlanAmendment No.4 to Strategic Stock PlanTermination of the Executive Award Plan of Sonat IncAmended Omnibus Plan for Management EmployeesAmendment No.1 to Omnibus Plan for Management EmployeesAmendment No.2 to Omnibus Plan for Management EmployeesAmendment No.3 to Omnibus Plan for ManagementAmendment No.4 to Omnibus Plan for Management EmployeesAmendment No.1 to Amended Severance Pay PlanAmendment No.2 to 2005 Compensation Plan for Non-Employee DirectorsAmendment No.1 to 2005 Omnibus Incentive Compensation PlanAmendment No.1 to 2005 Supplemental Benefits PlanRatio of Earnings to Combined Fixed Charges and Preferred Stock DividendsSubsidiariesConsent of Ernst & Young LLPConsent of PricewaterhouseCoopers LLPConsent 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 ReportRyder Scott Reserve Report




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##### Table of Contents



/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 equivalentsMDth
    
    =
    
    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
   3




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##### Table of Contents



PART I
 
 ITEM 1. BUSINESS
 Business and Strategy
  Natural Gas Transmission.
 Exploration and Production.
  Pipelines Segment
   4




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##### Table of Contents




    
    Successfully executing on our backlog of committed expansion
projects;
    
    Developing new growth projects in our market and supply areas;
    
    Recontracting or contracting available or expiring capacity;
    
    Focusing on efficiency and synergies  across our systems;
    
    Ensuring the safety of our pipeline systems and assets; and
    
    Providing outstanding customer service.
   As of December 31, 2007Transmission
    
    Supply and
    
    Ownership
    
    Miles of
    
    Design
    
    Storage
    
    Average Throughput(1)System
    
    Market Region
    
    Percentage
    
    Pipeline
    
    Capacity
    
    Capacity
    
    2007
    
    2006
    
    2005(Percent)
    
    
    
    
    
    (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.
    
    
    100
    
    
    
    13,700
    
    
    
    7,069
    
    
    
    92
    
    
    
    4,880
    
    
    
    4,534
    
    
    
    4,443El Paso Natural Gas
(EPNG)
    
    Extends from San Juan,
Permian, Anadarko
basins and via
interconnects the Rocky
Mountains to
California, its single
largest market, as well
as markets in Arizona,
Nevada, New Mexico,
Oklahoma, Texas and
northern Mexico.
    
    
    100
    
    
    
    10,200
    
    
    5,650(2)
    
    
    44
    
    
    
    4,189
    
    
    
    4,179
    
    
    
    4,053Mojave Pipeline
(MPC)
    
    Connects with the EPNG
system near Cadiz,
California, the EPNG
and Transwestern
systems at Topock,
Arizona and to the Kern
River Gas Transmission
Company system in
California. This system
also extends to
customers in the
vicinity of
Bakersfield,
California.
    
    
    100
    
    
    
    400
    
    
    400(4)
    
    
    
    
    
    
    458
    
    
    
    461
    
    
    
    161Cheyenne Plains Gas 
Pipeline(CPG)(3)
    
    Extends from Cheyenne
hub and Yuma County in
Colorado to various
pipeline
interconnections near
Greensburg, Kansas.
    
    
    100
    
    
    
    400
    
    
    
    861
    
    
    
    
    
    
    
    735
    
    
    
    583
    
    
    
    433
 
 (1)
    
    Includes throughput transported on behalf of affiliates.(2)
    
    Reflects winter-sustainable west-flow capacity of 4,850 MMcf/d and approximately 800 MMcf/d of east-end delivery capacity.(3)
    
    Completed in 2005(4)
    
    Reflects east to west flow capacity 5




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As of December 31, 2007Transmission
    
    Supply and
    
    Ownership
    
    Miles of
    
    Design
    
    Storage
    
    
    Average Throughput(1)System
    
    Market Region
    
    Interest
    
    Pipeline(1)
    
    Capacity(1)
    
    Capacity(1)
    
    
    2007
    
    2006
    
    2005(Percent)
    
    
    
    
    
    (MMcf/d)
    
    (Bcf)
    
    
    (BBtu/d)Southern 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.
    
    
    97
    
    
    
    7,600
    
    
    
    3,665
    
    
    60
    
    
    
    2,345
    
    
    
    2,167
    
    
    
    1,984Colorado 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.
    
    
    97
    
    
    
    4,000
    
    
    
    3,048
    
    
    29
    
    
    
    2,339
    
    
    
    2,008
    
    
    
    1,902Wyoming Interstate (WIC)(2)
    
    Extends from western Wyoming,
eastern Utah, western
Colorado and the Powder River
Basin to various pipeline
interconnections near
Cheyenne, Wyoming.
    
    
    67
    
    
    
    800
    
    
    
    2,721
    
    
    
    
    
    
    2,071
    
    
    
    1,914
    
    
    
    1,572Florida Gas 
Transmission(3)
(FGT)
    
    Extends from South Texas to
South Florida.
    
    
    50
    
    
    
    4,881
    
    
    
    2,100
    
    
    
    
    
    
    2,056
    
    
    
    2,018
    
    
    
    1,916Samalayuca Pipeline and
Gloria a Dios Compression
Station(4)
    
    Extends from U.S.-Mexico
border to the state of
Chihuahua, Mexico.
    
    
    50
    
    
    
    23
    
    
    
    460
    
    
    
    
    
    
    462
    
    
    
    442
    
    
    
    423San Fernando Pipeline(4)
    
    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)
    
    Includes throughput transported on behalf of affiliates and represents the systems totals and are not adjusted for our ownership interest.(2)
    
    Includes the recently completed Kanda expansion project placed in
service in January 2008.(3)
    
    We have a 50 percent equity interest in Citrus Corp. (Citrus), which owns this system.(4)
    
    We have a 50 percent equity interest in Gasoductos de Chihuahua, which owns these systems.  6




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Existing
    
    Capacity
    
    
    
    AnticipatedProject
    
    System
    
    (MMcf/d)
    
    Description
    
    Completion or In-Service DateEssex Middlesex Project
    
    TGP
    
    
    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 2008Medicine Bow Expansion
    
    WIC
    
    
    330
    
    
    To construct a new 24,930 horsepower
compression facility which increases
capacity from the Powder River Basin in
northeast Wyoming to the WIC mainline
near the Cheyenne Hub
    
    July 2008Cheyenne Plains Expansion
    
    CPG
    
    
    70
    
    
    To construct a new compression facility
comprised of 10,310 horsepower at the
Kirk Compressor Station in Yuma County,
Colorado
    
    July 2008Cypress Phase II
    
    SNG
    
    
    114
    
    
    To add 10,350 horsepower of additional
compression on pipeline facilities
extending southward from our Elba Island
facility
    
    May 2008Cypress Phase III
    
    SNG
    
    
    161
    
    
    To add 20,700 horsepower of additional
compression on pipeline facilities
extending southward from our Elba Island
facility
    
    January 2011Southeast
Supply Header(Phase I)
    
    SNG
    
    
    140
    
    
    To construct 115 miles of pipeline to the
western portion of our system and provide
access through pipeline interconnects to
several supply basins
    
    June 2008
 Intrastate Transmission Systems
  Underground Natural Gas Storage Facilities
  As of December 31, 2007Ownership
    
    StorageStorage Entity
    
    Interest
    
    Capacity(1)
    
    Location(Percent)
    
    (Bcf)Bear Creek Storage
    
    100
    
    58
    
    LouisianaYoung Gas Storage
    
    48
    
    6
    
    Colorado
 
 (1)
    
    Approximately 58 Bcf is contracted to affiliates. Amounts are not adjusted for our ownership interest. LNG Facility
  7




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Markets and Competition
     
  8




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TGP
 Customer Information
    
    Contract Information
    
    CompetitionApproximately 440 firm and
interruptible customers.
    
    Approximately 500
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.Major Customer:National Grid USA and subsidiaries(722 BBtu/d)
    
    Expire in 2009-2027.EPNGApproximately 140 firm and
interruptible customers
    
    Approximately 190
firm transportation
contracts. Weighted
average remaining
contract term of
approximately four
years.
    
    EPNG faces
competition in the
west and southwest
from other existing
and proposed
pipelines, from
California storage
facilities, and
from alternative
energy sources that
are used to
generate
electricity such as
hydroelectric
power, nuclear
energy, wind,
solar, coal and
fuel oil. In
addition,
construction of
facilities to bring
LNG into California
and northern Mexico
are underway.Major Customers:Southern California Gas Company(187 BBtu/d)
    
    Expires in 2009.(246 BBtu/d)
    
    Expires in 2010.(323 BBtu/d)
    
    Expires in 2011.Southwest Gas Corporation(11 BBtu/d)
    
    Expires in 2008.(603 BBtu/d)
    
    Expire in 2011-2015.MPCApproximately 20 firm and
interruptible customers
    
    Approximately five
firm transportation
contracts. Weighted
average remaining
contract term of
approximately eight
years.
    
    MPC faces
competition from
other existing and
proposed pipelines,
and alternative
energy sources that
are used to
generate
electricity such as
hydroelectric
power, nuclear
energy, wind,
solar, coal and
fuel oil. In
addition,
construction of
facilities to bring
LNG into California
and northern Mexico
are underway.Major Customer:EPNG(312 BBtu/d)
    
    Expires in 2015.
 9




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##### Table of Contents



CPG


Customer Information
    
    Contract Information
    
    CompetitionApproximately 50 firm and
interruptible customers
    
    Approximately 30
firm transportation
contracts. Weighted
average remaining
contract term of
approximately eight
years.
    
    CPG competes
directly with other
interstate
pipelines serving
the mid-continent
region. Indirectly,
CPG competes with
pipelines that
transport Rocky
Mountain gas to
other markets.Major Customers:Oneok Energy Services Company
L.P.
    
    Expires in 2015.(195 BBtu/d)Encana Marketing (USA) Inc.
    
    Expires in 2015.(170 BBtu/d)Anadarko Petroleum Corporation
    
    Expire in 2015-2016.(195 BBtu/d)Coral Energy Resources, L.P.
    
    Expires in 2019.(125 BBtu/d)SNGApproximately 280 firm and
interruptible customers
    
    Approximately 190
firm transportation
contracts. Weighted
average remaining
contract term of
approximately six
years.
    
    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, 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 sources.Major Customers:Atlanta Gas Light Company
      (981 BBtu/d)
    
    Expire in 2008-2015.Southern Company Services(418 BBtu/d)
    
    Expire in 2010-2018.Alabama Gas Corporation(413 BBtu/d)
    
    Expire in 2010-2013.SCANA Corporation(315 BBtu/d)
    
    Expire in 2010-2019.
 10




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##### Table of Contents



CIG
 Customer Information
    
    Contract Information
    
    CompetitionApproximately 120 firm and
interruptible customers
    
    Approximately 180
firm transportation
contracts. Weighted
average remaining
contract term of
approximately five
years.
    
    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, an
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
interstate
pipelines that are
directly connected
to its supply
sources. CIG faces
competition from
other existing
pipelines and
alternative energy
sources that are
used to generate
electricity such as
hydroelectric
power, wind, solar,
coal and fuel oil.Major Customers:PSCo(187 BBtu/d)
    
    Expires in 2008.(9 BBtu/d)
    
    Expires in 2009.(1,106 BBtu/d)
    
    Expire in 2012-2014.Williams Gas Marketing, Inc.(53 BBtu/d)
    
    Expires in 2009.(113 BBtu/d)
    
    Expires in 2010.(350 BBtu/d)
    
    Expire in 2011-2013.Anadarko Petroleum Corporation(70 BBtu/d)
    
    Expires in 2008.(12 BBtu/d)
    
    Expires in 2009.(80 BBtu/d)
    
    Expires in 2010.(128 BBtu/d)
    
    Expire in 2011-2015.WIC(1)Approximately 50 firm and
interruptible customers
    
    Approximately 50
firm transportation
contracts. Weighted
average remaining
contract term of
approximately ten
years.
    
    WIC competes with
existing pipelines
to provide
transportation
services from supply basins in northwest Colorado, eastern Utah and
Wyoming to
pipeline
interconnects in
northeast Colorado,
and western Wyoming.Major Customers:Williams Gas Marketing, Inc.(25 BBtu/d)
    
    Expires in 2008.(84 BBtu/d)
    
    Expires in 2010.(744 BBtu/d)
    
    Expire in 2013-2021.Anadarko Petroleum Corporation(25 BBtu/d)
    
    Expires in 2008.(810 BBtu/d)
    
    Expire in 2009-2022.
 (1)
    
    Information included has been adjusted to reflect the
completion of the Kanda expansion project placed in service in
January 2008. 11




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Regulatory Environment.
 
    
    rates and charges for natural gas transportation, storage 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.
  12




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Exploration and Production Segment
   United States
 Onshore.
 2007AverageNet
    
    Capital
    
    ProductionArea
    
    Description
    
    Acres
    
    Investment
    
    (MMcfe/d)(In millions)East Texas/North 
Louisiana
(Arklatex)
    
    Concentrated land positions primarily focused on
tight gas sands production in the Travis
Peak/Hosston, Bossier and Cotton Valley
formations. The Peoples acquisition added to our
existing asset in this area most notably in
Logansport, Bald Prairie, Bethany, Minden and
Bethany Longstreet fields. We also have land
positions in the Mississippi area, primarily in
Hub Field located on the southern edge of the
Mississippi Salt Basin.
    
    
    113,000
    
    
    $
    260
    
    
    
    136Black 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.
    
    
    171,000
    
    
    $
    51
    
    
    
    62Mid-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.
    
    
    456,000
    
    
    $
    40
    
    
    
    30Rocky Mountains
(Rockies)
    
    Primarily in Wyoming and Utah with a focus in the
Powder River and Uinta basins, consisting
predominantly of operated oil fields utilizing
both primary and secondary recovery methods
combined with non-operated coal bed methane
fields. We operate the Altamont and Bluebell
processing plants and related gathering systems in
Utah. We also have a non-operated working
interest primarily in the Stadium Unit in the
Williston Basin of North Dakota, which is
undergoing secondary recovery.
    
    
    357,000
    
    
    $
    79
    
    
    
    71
 13




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2007AverageNet
    
    Capital
    
    ProductionArea
    
    Description
    
    Acres
    
    Investment
    
    (MMcfe/d)(In millions)Raton 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. We also have
working interests in land positions in the San
Juan Basin primarily in the Fruitland Coal and
Dakota formations and the tight gas formations in
Pictured Cliffs and Mesaverde.
    
    
    605,000
    
    
    $
    113
    
    
    
    75
  Texas Gulf Coast.
 2007AverageCapital
    
    ProductionArea
    
    Description
    
    Net Acres
    
    Investment
    
    (MMcfe/d)(In millions)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.
We also have assets
in the Alvarado and
Kelsey fields and
in Starr and Brooks
Counties with an
average working
interest of over 65
percent.
    
    
    83,000
    
    
    $
    128
    
    
    
    132Upper Gulf Coast Wilcox
    
    Located onshore
Texas Gulf Coast,
including Renger,
Dry Hollow, Brushy
Creek and Speaks
fields in Lavaca
County and
Graceland Field,
located in
Colorado, County.
    
    
    37,000
    
    
    $
    56
    
    
    
    32South Texas Wilcox
    
    Includes positions
in which we have
working interests
in Bob West,
Jennings Ranch and
Roleta fields in
Zapata County. We
also have working
interests in the
Laredo and Loma
Novia fields in
Webb and Duval
counties.
    
    
    79,000
    
    
    $
    143
    
    
    
    49
 14




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##### Table of Contents



Gulf of Mexico and south Louisiana.
 2007AverageCapital
    
    ProductionArea
    
    Description
    
    Net Acres
    
    Investment
    
    (MMcfe/d)(In millions)Gulf of Mexico
    
    Primarily drilling
interests in 148
Blocks south of the
Louisiana, Texas
and Alabama
shorelines focused
on deep (greater
than 12,000 feet)
natural gas and oil
reserves in
relatively shallow
water depths (less
than 300 feet).
    
    
    543,000
    
    
    $
    281
    
    
    
    174South Louisiana
    
    Primarily in
Vermilion Parish
and associated bays
and inland waters
in southwestern
Louisiana covered
by the Catapult 3D
seismic project. We
have internally
processed 2,800
square miles of
contiguous 3D
seismic data in
this project.
    
    
    21,000
    
    
    $
    28
    
    
    
    17
 Unconsolidated Investment in Four Star.
 International
 Brazil.
 Egypt.
 15




---



##### Table of Contents



Natural Gas and Oil Properties
 Natural Gas, Oil and Condensate and NGL Reserves and Production
  Net Proved Reserves
    
    2007Natural Gas
    
    Oil/Condensate
    
    NGL
    
    Total
    
    Production(MMcf)
    
    (MBbls)
    
    (MBbls)
    
    (MMcfe)
    
    (Percent)
    
    (MMcfe)Reserves and Production by RegionUnited StatesOnshore
    
    
    1,567,666
    
    
    
    36,308
    
    
    
    301
    
    
    
    1,787,318
    
    
    
    63
    %
    
    
    136,701Texas Gulf Coast
    
    
    471,448
    
    
    
    3,806
    
    
    
    9,205
    
    
    
    549,513
    
    
    
    19
    %
    
    
    77,633Gulf of Mexico and 
south Louisiana
    
    
    207,546
    
    
    
    9,560
    
    
    
    608
    
    
    
    268,555
    
    
    
    9
    %
    
    
    69,671Total United States
    
    
    2,246,660
    
    
    
    49,674
    
    
    
    10,114
    
    
    
    2,605,386
    
    
    
    91
    %
    
    
    284,005Brazil
    
    
    51,206
    
    
    
    32,710
    
    
    
    
    
    
    
    247,468
    
    
    
    9
    %
    
    
    5,237Total
    
    
    2,297,866
    
    
    
    82,384
    
    
    
    10,114
    
    
    
    2,852,854
    
    
    
    100
    %
    
    
    289,242Unconsolidated investment in
 Four Star
    
    
    200,109
    
    
    
    2,858
    
    
    
    6,411
    
    
    
    255,722
    
    
    
    100
    %
    
    
    25,470Reserves by ClassificationUnited StatesProducing
    
    
    1,419,621
    
    
    
    26,578
    
    
    
    6,679
    
    
    
    1,619,159
    
    
    
    62
    %Non-Producing
    
    
    318,475
    
    
    
    8,492
    
    
    
    1,453
    
    
    
    378,147
    
    
    
    15
    %Undeveloped
    
    
    508,564
    
    
    
    14,604
    
    
    
    1,982
    
    
    
    608,080
    
    
    
    23
    %Total proved
    
    
    2,246,660
    
    
    
    49,674
    
    
    
    10,114
    
    
    
    2,605,386
    
    
    
    100
    %BrazilProducing
    
    
    15,229
    
    
    
    342
    
    
    
    
    
    
    
    17,281
    
    
    
    7
    %Non-Producing
    
    
    3,414
    
    
    
    338
    
    
    
    
    
    
    
    5,444
    
    
    
    2
    %Undeveloped
    
    
    32,563
    
    
    
    32,030
    
    
    
    
    
    
    
    224,743
    
    
    
    91
    %Total proved
    
    
    51,206
    
    
    
    32,710
    
    
    
    
    
    
    
    247,468
    
    
    
    100
    %WorldwideProducing
    
    
    1,434,850
    
    
    
    26,920
    
    
    
    6,679
    
    
    
    1,636,440
    
    
    
    58
    %Non-Producing
    
    
    321,889
    
    
    
    8,830
    
    
    
    1,453
    
    
    
    383,591
    
    
    
    13
    %Undeveloped
    
    
    541,127
    
    
    
    46,634
    
    
    
    1,982
    
    
    
    832,823
    
    
    
    29
    %Total proved
    
    
    2,297,866
    
    
    
    82,384
    
    
    
    10,114
    
    
    
    2,852,854
    
    
    
    100
    %Unconsolidated investment in
 Four StarProducing
    
    
    167,114
    
    
    
    2,804
    
    
    
    5,316
    
    
    
    215,828
    
    
    
    85
    %Non-Producing
    
    
    3,072
    
    
    
    
    
    
    
    29
    
    
    
    3,246
    
    
    
    1
    %Undeveloped
    
    
    29,923
    
    
    
    54
    
    
    
    1,066
    
    
    
    36,648
    
    
    
    14
    %Total Four Star
    
    
    200,109
    
    
    
    2,858
    
    
    
    6,411
    
    
    
    255,722
    
    
    
    100
    %
   16




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##### Table of Contents



Acreage and Wells
  Developed
    
    Undeveloped
    
    TotalGross(1)
    
    Net(2)
    
    Gross(1)
    
    Net(2)
    
    Gross(1)
    
    Net(2)AcreageUnited StatesOnshore
    
    
    1,026,566
    
    
    
    627,034
    
    
    
    1,524,237
    
    
    
    1,075,443
    
    
    
    2,550,803
    
    
    
    1,702,477Texas Gulf Coast
    
    
    173,282
    
    
    
    119,025
    
    
    
    114,842
    
    
    
    80,396
    
    
    
    288,124
    
    
    
    199,421Gulf of Mexico and south Louisiana
    
    
    517,597
    
    
    
    376,378
    
    
    
    220,314
    
    
    
    187,506
    
    
    
    737,911
    
    
    
    563,884Total United States
    
    
    1,717,445
    
    
    
    1,122,437
    
    
    
    1,859,393
    
    
    
    1,343,345
    
    
    
    3,576,838
    
    
    
    2,465,782Brazil
    
    
    49,262
    
    
    
    17,242
    
    
    
    1,158,643
    
    
    
    343,563
    
    
    
    1,207,905
    
    
    
    360,805Egypt
    
    
    
    
    
    
    
    
    
    
    1,247,064
    
    
    
    1,195,272
    
    
    
    1,247,064
    
    
    
    1,195,272Worldwide Total
    
    
    1,766,707
    
    
    
    1,139,679
    
    
    
    4,265,100
    
    
    
    2,882,180
    
    
    
    6,031,807
    
    
    
    4,021,859
 
 (1)
    
    Gross interest reflects the total acreage we participated in, regardless of our ownership interest in the acreage.(2)
    
    Net interest is the aggregate of the fractional working interests that we have in the gross acreage.  17




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##### Table of Contents



Wells Being Drilled at December 31,Natural Gas
    
    Oil
    
    Total
    
    2007Gross(1)
    
    Net(2)
    
    Gross(1)
    
    Net(2)
    
    Gross(1)
    
    Net(2)(3)
    
    Gross(1)
    
    Net(2)Productive WellsUnited StatesOnshore
    
    
    4,901
    
    
    
    3,627
    
    
    
    658
    
    
    
    495
    
    
    
    5,559
    
    
    
    4,122
    
    
    
    74
    
    
    
    61Texas Gulf Coast
    
    
    1,643
    
    
    
    1,167
    
    
    
    
    
    
    
    
    
    
    
    1,643
    
    
    
    1,167
    
    
    
    8
    
    
    
    7Gulf of Mexico
and south
Louisiana
    
    
    193
    
    
    
    127
    
    
    
    56
    
    
    
    31
    
    
    
    249
    
    
    
    158
    
    
    
    2
    
    
    
    1Total
    
    
    6,737
    
    
    
    4,921
    
    
    
    714
    
    
    
    526
    
    
    
    7,451
    
    
    
    5,447
    
    
    
    84
    
    
    
    69Brazil
    
    
    4
    
    
    
    1
    
    
    
    6
    
    
    
    2
    
    
    
    10
    
    
    
    3
    
    
    
    
    
    
    
    Worldwide Total
    
    
    6,741
    
    
    
    4,922
    
    
    
    720
    
    
    
    528
    
    
    
    7,461
    
    
    
    5,450
    
    
    
    84
    
    
    
    69
 Net Exploratory(2)(4)
    
    Net Development(2)(4)2007
    
    2006
    
    2005
    
    2007
    
    2006
    
    2005Wells DrilledUnited StatesProductive
    
    
    214
    
    
    
    106
    
    
    
    86
    
    
    
    238
    
    
    
    319
    
    
    
    279Dry
    
    
    12
    
    
    
    6
    
    
    
    2
    
    
    
    1
    
    
    
    2
    
    
    
    4Total
    
    
    226
    
    
    
    112
    
    
    
    88
    
    
    
    239
    
    
    
    321
    
    
    
    283BrazilProductive
    
    
    3
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Dry
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Total
    
    
    3
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    WorldwideProductive
    
    
    217
    
    
    
    106
    
    
    
    86
    
    
    
    238
    
    
    
    319
    
    
    
    279Dry
    
    
    12
    
    
    
    6
    
    
    
    2
    
    
    
    1
    
    
    
    2
    
    
    
    4Total
    
    
    229
    
    
    
    112
    
    
    
    88
    
    
    
    239
    
    
    
    321
    
    
    
    283
 
 (1)
    
    Gross interest reflects the total wells we participated in, regardless of our ownership interest.(2)
    
    Net interest is the aggregate of the fractional working interests that we have in the gross wells or gross wells drilled.(3)
    
    At December 31, 2007, we operated 4,905 of the 5,450 net productive wells.(4)
    
    In 2007, there was a reduction in the number of non-operated development wells drilled in the Rockies and an increase in the number of exploration wells drilled in the Raton Basin.  18




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##### Table of Contents



Net Production, Sales Prices, Transportation and Production Costs
  2007
    
    
    2006
    
    
    2005Consolidated Volumes, Prices, and Costs per Unit:Net Production VolumesUnited StatesNatural gas (MMcf)
    
    
    238,021
    
    
    
    213,262
    
    
    
    206,714Oil, condensate and NGL (MBbls)
    
    
    7,664
    
    
    
    7,439
    
    
    
    7,516Total (MMcfe)
    
    
    284,005
    
    
    
    257,899
    
    
    
    251,807Brazil(1)Natural gas (MMcf)
    
    
    4,295
    
    
    
    7,140
    
    
    
    15,578Oil, condensate and NGL (MBbls)
    
    
    157
    
    
    
    247
    
    
    
    620Total (MMcfe)
    
    
    5,237
    
    
    
    8,619
    
    
    
    19,300WorldwideNatural gas (MMcf)
    
    
    242,316
    
    
    
    220,402
    
    
    
    222,292Oil, condensate and NGL (MBbls)
    
    
    7,821
    
    
    
    7,686
    
    
    
    8,136Total (MMcfe)
    
    
    289,242
    
    
    
    266,518
    
    
    
    271,107Total (MMcfe/d)
    
    
    792
    
    
    
    730
    
    
    
    743Natural Gas Average Realized Sales Price ($/Mcf)United StatesExcluding hedges
    
    $
    6.60
    
    
    $
    6.77
    
    
    $
    7.92Including hedges
    
    $
    7.36
    
    
    $
    6.50
    
    
    $
    6.69BrazilExcluding hedges
    
    $
    2.61
    
    
    $
    2.61
    
    
    $
    2.33Including hedges
    
    $
    2.61
    
    
    $
    2.61
    
    
    $
    2.33WorldwideExcluding hedges
    
    $
    6.53
    
    
    $
    6.64
    
    
    $
    7.53Including hedges
    
    $
    7.28
    
    
    $
    6.38
    
    
    $
    6.39Oil, Condensate and NGL Average Realized Sales Price ($/Bbl)United StatesExcluding hedges
    
    $
    63.56
    
    
    $
    55.95
    
    
    $
    45.86Including hedges
    
    $
    63.56
    
    
    $
    55.95
    
    
    $
    45.86BrazilExcluding hedges
    
    $
    70.86
    
    
    $
    64.02
    
    
    $
    53.42Including hedges
    
    $
    41.27
    
    
    $
    54.48
    
    
    $
    42.42WorldwideExcluding hedges
    
    $
    63.71
    
    
    $
    56.21
    
    
    $
    46.43Including hedges
    
    $
    63.11
    
    
    $
    55.90
    
    
    $
    45.60Average Transportation CostsUnited StatesNatural gas ($/Mcf)
    
    $
    0.27
    
    
    $
    0.24
    
    
    $
    0.20Oil, condensate and NGL ($/Bbl)
    
    $
    0.83
    
    
    $
    0.85
    
    
    $
    0.69WorldwideNatural gas ($/Mcf)
    
    $
    0.27
    
    
    $
    0.23
    
    
    $
    0.18Oil, condensate and NGL ($/Bbl)
    
    $
    0.81
    
    
    $
    0.82
    
    
    $
    0.63
 19




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##### Table of Contents



2007
    
    
    2006
    
    
    2005Average Production Costs ($/Mcfe)United StatesLease operating costs
    
    $
    0.86
    
    
    $
    0.97
    
    
    $
    0.73Production taxes
    
    
    0.31
    
    
    
    0.28
    
    
    
    0.27Total production costs
    
    $
    1.17
    
    
    $
    1.25
    
    
    $
    1.00BrazilLease operating costs
    
    $
    1.63
    
    
    $
    0.28
    
    
    $
    0.42Production taxes
    
    
    0.51
    
    
    
    0.53
    
    
    
    Total production costs
    
    $
    2.14
    
    
    $
    0.81
    
    
    $
    0.42WorldwideLease operating costs
    
    $
    0.88
    
    
    $
    0.95
    
    
    $
    0.72Production taxes
    
    
    0.31
    
    
    
    0.29
    
    
    
    0.24Total production costs
    
    $
    1.19
    
    
    $
    1.24
    
    
    $
    0.96Unconsolidated affiliate volumes (Four Star)(2)Natural gas (MMcf)
    
    
    19,380
    
    
    
    18,140
    
    
    
    6,689Oil, condensate and NGL (MBbls)
    
    
    1,015
    
    
    
    1,087
    
    
    
    359Total equivalent volumesMMcfe
    
    
    25,470
    
    
    
    24,663
    
    
    
    8,844MMcfe/d
    
    
    70
    
    
    
    68
    
    
    
    24
 
 (1)
    
    Production volumes in Brazil decreased due to a contractual reduction of our ownership interest in the Pescada-Arabaiana Fields in early 2006.(2)
    
    Includes our proportionate share of volumes in Four Star which was acquired in 2005. In the third quarter of 2007, we increased our ownership interest in Four Star from 43 percent to 49 percent. 20




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##### Table of Contents



Acquisition, Development and Exploration Expenditures
  2007
    
    
    2006
    
    
    2005(In millions)United StatesAcquisition Costs:Proved
    
    $
    964
    
    
    $
    2
    
    
    $
    643Unproved
    
    
    262
    
    
    
    34
    
    
    
    143Development Costs
    
    
    735
    
    
    
    738
    
    
    
    503Exploration Costs:Delay rentals
    
    
    6
    
    
    
    6
    
    
    
    3Seismic acquisition and reprocessing
    
    
    19
    
    
    
    23
    
    
    
    7Drilling
    
    
    373
    
    
    
    294
    
    
    
    133Asset Retirement Obligations
    
    
    38
    
    
    
    3
    
    
    
    1Total full cost pool expenditures
    
    
    2,397
    
    
    
    1,100
    
    
    
    1,433Non-full cost pool expenditures
    
    
    13
    
    
    
    8
    
    
    
    22Total costs incurred(1)
    
    $
    2,410
    
    
    $
    1,108
    
    
    $
    1,455Acquisition
of unconsolidated investment in Four Star(2)
    
    $
    27
    
    
    $
    
    
    
    $
    769Brazil and Other International(1)Acquisition Costs:Proved
    
    $
    
    
    
    $
    2
    
    
    $
    8Unproved
    
    
    5
    
    
    
    1
    
    
    
    1Development Costs
    
    
    26
    
    
    
    40
    
    
    
    6Exploration Costs:Seismic acquisition and reprocessing
    
    
    6
    
    
    
    7
    
    
    
    7Drilling
    
    
    193
    
    
    
    46
    
    
    
    8Asset Retirement Obligations
    
    
    7
    
    
    
    
    
    
    
    Total full cost pool expenditures
    
    
    237
    
    
    
    96
    
    
    
    30Non-full cost pool expenditures
    
    
    1
    
    
    
    
    
    
    
    Total costs incurred
    
    $
    238
    
    
    $
    96
    
    
    $
    30WorldwideAcquisition Costs:Proved
    
    $
    964
    
    
    $
    4
    
    
    $
    651Unproved
    
    
    267
    
    
    
    35
    
    
    
    144Development Costs
    
    
    761
    
    
    
    778
    
    
    
    509Exploration Costs:Delay rentals
    
    
    6
    
    
    
    6
    
    
    
    3Seismic acquisition and reprocessing
    
    
    25
    
    
    
    30
    
    
    
    14Drilling
    
    
    566
    
    
    
    340
    
    
    
    141Asset Retirement Obligations
    
    
    45
    
    
    
    3
    
    
    
    1Total full cost pool expenditures
    
    
    2,634
    
    
    
    1,196
    
    
    
    1,463Non-full cost pool expenditures
    
    
    14
    
    
    
    8
    
    
    
    22Total costs incurred(1)
    
    $
    2,648
    
    
    $
    1,204
    
    
    $
    1,485Acquisition of unconsolidated investment in Four Star(2)
    
    $
    27
    
    
    $
    
    
    
    $
    769
 
 (1)
    
    Costs incurred for Egypt were $10 million and $4 million for the years ended December 31, 2007 and 2006.(2)
    
    In 2005, amount includes deferred tax adjustments of $179 million related to the acquisition of full-cost
pool properties and $217 million related to the acquisition of our unconsolidated investment in Four Star.  21




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##### Table of Contents



Markets and Competition
   Regulatory Environment.
  22




---



##### Table of Contents



Marketing Segment
  
    
    Production-Related Natural Gas and Oil Derivative Contracts.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.
    
    Legacy Natural Gas and Power Contracts.Includes a variety of natural gas derivative
contracts and long-term supply obligations, including our Midland Cogeneration Venture
(MCV) supply agreement and power contracts in the
Pennsylvania-New Jersey-Maryland (PJM) region.
 Production-Related Natural Gas and Oil Derivative Contracts
  2008
    
    2009Natural Gas (TBtu)Volumes with floor and ceiling prices
    
    
    
    
    
    
    17Oil (MBbls)Volumes with floor and ceiling prices
    
    
    930
    
    
    
    
 Contracts Related to Legacy Trading Operations
 Natural gas transportation-related contracts.
 Affiliated Pipelines(1)
    
    Other PipelinesDaily capacity (MMBtu/d)
    
    521,000
    
    63,000Expiration
    
    2009 to 2028
    
    2012 to 2026Receipt points
    
    Various
    
    VariousDelivery points
    
    Various
    
    Various
 
 (1)
    
    Primarily consists of contracts with TGP and EPNG. Other natural gas contracts.
 23




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##### Table of Contents



Power contracts.
 Markets, Competition and Regulatory Environment
  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 GasKhulna Power Co.
    
    Bangladesh
    
    
    74
    
    
    
    113
    
    
    BPDB
    
    
    2013
    
    
    Heavy Fuel OilTipitapa(3)
    
    Nicaragua
    
    
    60
    
    
    
    51
    
    
    Union Fenosa
    
    
    2014
    
    
    Heavy Fuel Oil
 
 (1)
    
    Ownership of these plants transferred to the power purchaser in January 2008.(2)
    
    In the third quarter of 2007, we received an offer from our partners to purchase this investment. For further discussion, see Item 8, Financial Statements, Note 17.(3)
    
    In December 2007, we signed an agreement to sell this facility which is expected to close in the first half of 2008.  Regulatory Environment.
 24




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##### Table of Contents



Environmental
  Employees
  Executive Officers of the Registrant
  OfficerName
    
    Office
    
    Since
    
    AgeDouglas L. Foshee
    
    President and Chief Executive Officer of El Paso
    
    
    2003
    
    
    
    48D. Mark Leland
    
    Executive Vice President and Chief Financial Officer of El Paso
    
    
    2005
    
    
    
    46Robert W. Baker
    
    Executive Vice President and General Counsel of El Paso
    
    
    2002
    
    
    
    51Brent Smolik
    
    Executive Vice President of El Paso and President of El Paso
Exploration & Production Company
    
    
    2006
    
    
    
    46Susan B. Ortenstone
    
    Senior Vice President (Human Resources and Administration) of El Paso
    
    
    2003
    
    
    
    51James C. Yardley
    
    Executive Vice President, Pipeline
Group
    
    
    2005
    
    
    
    56James J. Cleary
    
    President of Western Pipeline Group
    
    
    2005
    
    
    
    53Daniel B. Martin
    
    Senior Vice President of Pipeline Operations
    
    
    2005
    
    
    
    51
   25




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Available Information
  26




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##### Table of Contents



ITEM 1A. RISK FACTORS
 CAUTIONARY STATEMENT FOR PURPOSES OF THE SAFE HARBOR PROVISIONS OF THE PRIVATE SECURITIES
LITIGATION REFORM ACT OF 1995
   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 natural gas supply sources, such as LNG;
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
    
    continued development of additional sources of gas supply
that can be accessed;
    
    decreased natural gas demand due to various factors,
including increases in prices and the availability or increased demand of alternative energy sources
such as hydroelectric power, nuclear energy, wind, solar, coal 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 including prolonged recessionary periods that might
negatively impact natural gas demand and the capital markets;
    
    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.
 Certain of our systems transportation services are subject to long-term, fixed-price negotiated
rate contracts that are not subject to adjustment, even if our cost to perform such services
exceeds the revenues received from such contracts, and, as a result, our costs could exceed our
revenues received under such contracts.
  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;
    
    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.
  28




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
    
    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  countries producing oil and LNG.
 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 the FERC and other 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,
regulations, and orders, 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, contractor productivity or other factors beyond our control, that we may not be able
to recover from our
customers which may be material;
    
    the lack of future growth in natural gas supply; and
    
    the lack of transportation, storage or throughput commitments.
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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 the following factors.
  
    
    the results of future drilling activity;
    
    the availability and 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;
    
    our ability to expand our leased land positions in desirable areas, which often are
subject to intensely competitive conditions from other companies;
    
our ability to successfully integrate acquisitions;
    
    adverse changes in future tax policies, rates, and drilling or production incentives by
state, federal, or foreign governments;
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
    
    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.
   31




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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.
   32




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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, customer
authorizations 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.
  The agencies that regulate our pipeline businesses and their customers could affect our
profitability.
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Environmental compliance and remediation costs and the costs of environmental liabilities could
exceed our estimates.
   
    
    estimating pollution control and clean up costs, including 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;
    
    evaluating and understanding environmental laws and regulations, including their
interpretation and enforcement; and
    
    changing environmental laws and regulations that may increase our costs.
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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.
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Adverse changes in general domestic economic conditions could adversely affect our operating
results, financial condition, or liquidity.
  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.
 36




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##### Table of Contents



ITEM 1B. UNRESOLVED STAFF COMMENTS
  
 ITEM 2. PROPERTIES
   
 ITEM 3. LEGAL PROCEEDINGS
  Fort Morgan Storage Field.
 Rawlins Plant Notice of Probable Violation
 Natural Buttes.
 
 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
  37




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PART II
 
 ITEM 5.
    
    MARKET FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF
EQUITY SECURITIES.
  Quarterly Stock Prices.
 High
    
    Low
    
    Dividends2007Fourth Quarter
    
    $
    18.37
    
    
    $
    15.29
    
    
    $
    0.04Third Quarter
    
    
    18.56
    
    
    
    15.00
    
    
    
    0.04Second Quarter
    
    
    17.43
    
    
    
    14.41
    
    
    
    0.04First Quarter
    
    
    15.66
    
    
    
    13.71
    
    
    
    0.042006Fourth 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
    
    
    
    0.04
 Stock Performance Graph.
 38




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##### Table of Contents



COMPARISON OF ANNUAL CUMULATIVE TOTAL RETURNS
 
 12/02
    
    12/03
    
    12/04
    
    12/05
    
    12/06
    
    12/07El Paso Corporation
    
    $
    100
    
    
    $
    120.27
    
    
    $
    155.64
    
    
    $
    184.60
    
    
    $
    234.61
    
    
    $
    267.31S&P 500 Stock Index
    
    $
    100
    
    
    $
    128.68
    
    
    $
    142.69
    
    
    $
    149.70
    
    
    $
    173.34
    
    
    $
    182.86S&P 500 Oil & Gas Storage & Transportation Index(1)
    
    $
    100
    
    
    $
    163.09
    
    
    $
    228.19
    
    
    $
    301.43
    
    
    $
    358.54
    
    
    $
    409.59New Peer Group
    
    $
    100
    
    
    $
    137.32
    
    
    $
    172.32
    
    
    $
    225.16
    
    
    $
    254.39
    
    
    $
    319.86Old Peer Group
    
    $
    100
    
    
    $
    137.51
    
    
    $
    172.76
    
    
    $
    226.38
    
    
    $
    256.51
    
    
    $
    328.44
 
 (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.
 39




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ITEM 6: SELECTED FINANCIAL DATA
  As of or for the Year Ended December 31,2007
    
    
    2006
    
    
    2005
    
    
    2004
    
    
    2003(In millions, except per common share amounts)Operating Results Data:Operating revenues
    
    $
    4,648
    
    
    $
    4,281
    
    
    $
    3,359
    
    
    $
    4,783
    
    
    $
    5,596Income (loss) from continuing operations
    
    $
    436
    
    
    $
    531
    
    
    $
    (506
    )
    
    $
    (1,032
    )
    
    $
    (795
    )Net income (loss) available to common stockholders
    
    $
    1,073
    
    
    $
    438
    
    
    $
    (633
    )
    
    $
    (947
    )
    
    $
    (1,883
    )Basic earnings (loss) per common share from continuing operations
    
    $
    0.57
    
    
    $
    0.73
    
    
    $
    (0.82
    )
    
    $
    (1.61
    )
    
    $
    (1.33
    )Diluted earnings (loss) per common share from continuing operations
    
    $
    0.57
    
    
    $
    0.72
    
    
    $
    (0.82
    )
    
    $
    (1.61
    )
    
    $
    (1.33
    )Cash dividends declared per common share
    
    $
    0.16
    
    
    $
    0.16
    
    
    $
    0.16
    
    
    $
    0.16
    
    
    $
    0.16Basic average common shares outstanding
    
    
    696
    
    
    
    678
    
    
    
    646
    
    
    
    639
    
    
    
    597Diluted average common shares outstanding
    
    
    699
    
    
    
    739
    
    
    
    646
    
    
    
    639
    
    
    
    597Financial Position Data:Total assets
    
    $
    24,579
    
    
    $
    27,261
    
    
    $
    31,840
    
    
    $
    31,398
    
    
    $
    36,968Long-term financing obligations, less current maturities
    
    
    12,483
    
    
    
    13,329
    
    
    
    16,282
    
    
    
    17,506
    
    
    
    19,193Minority Interest
    
    
    565
    
    
    
    31
    
    
    
    31
    
    
    
    367
    
    
    
    447Stockholders equity
    
    
    5,280
    
    
    
    4,186
    
    
    
    3,389
    
    
    
    3,438
    
    
    
    4,346
 Factors Affecting Trends.
  40




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ITEM 7. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 Overview
  Our
Business
 Results
of Operations
 Liquidity
and Capital Resources
 Off Balance Sheet Arrangements, Contractual Obligations, and Commodity-Based Derivative
Contracts
 Critical
Accounting Estimates
 Our Business
  Factors Influencing Our Profitability.
  
    
    Successfully executing on our backlog of committed expansion projects and developing new
growth projects in our market and supply areas;
    
    Contracting and recontracting pipeline capacity with our customers;
    
    Maintaining or obtaining approval by FERC of acceptable rates and terms of
service; and
    
    Improving operating efficiency.
  
    
    Increasing our natural gas and oil proved reserve base and production volumes
through successful drilling programs and/or acquisitions;
    
    Finding and producing natural gas and oil at a reasonable cost; and
    
    Managing price risks to optimize realized prices on our natural gas and oil production.
 41




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##### Table of Contents



Summary of Overall Performance in 2007.
 Area of Operations
    
    Significant HighlightsPipelines
    
    Completed and
entered into new expansion projects resulting in a
current backlog of almost $4 billion.Completed the sale of ANR, our Michigan storage assets and our 50 percent interest
in Great Lakes Gas Transmission for net cash proceeds of approximately $3.7
billionImplemented FERC approved rate case settlements for El Paso Natural Gas Company
and Mojave Pipeline CompanyCompleted a $575 million initial public offering of common units for El Paso
Pipeline Partners, L.P., a newly formed master limited partnership to enhance the
value and financial flexibility of our pipeline assets and provide a lower-cost
source of capital for new pipeline growth projectsReached an agreement (completed
February 2008) to acquire a 50 percent interest in the Gulf LNG Clean
Energy project, which is constructing an LNG
regasification terminal in MississippiExploration and
Production
    
    Met production and cost targets established for 2007 with increased production
volumes in each quarter of 2007High-graded our portfolio
through the acquisition of Peoples for $887 million,
adding proved reserves of 298 Bcfe, and progressed on our announced divestiture
programReplaced 129% of our worldwide
natural gas and oil reserves, excluding acquisitions, and 252%
including acquisitionsAchieved success in our exploration programs in BrazilManaged price risk through
derivative contracts which, when combined with our other
positions, provided higher realized commodity prices in 2007 and gives
us price protection on approximately two-thirds of our planned 2008
equivalent production.
  42




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##### Table of Contents



Outlook.
 Pipelines
 Exploration and Production
 Credit
Profile.
 
    
    Reducing debt by approximately $2.6 billion (including debt of our discontinued ANR
operations) primarily with proceeds from the sale of ANR;
    
    Refinancing approximately $2.0 billion of the debt of our subsidiaries SNG, EPNG, and
EPEP;
    
    Receiving upgraded senior unsecured debt ratings for El Paso of Ba3 with a positive outlook from
Moodys, BB- with a positive outlook from Standard and Poors and BB+ from Fitch Ratings
and receiving investment grade senior unsecured debt ratings on our pipeline
subsidiaries of Baa3 with a positive outlook from Moodys, BB with a positive outlook
from Standard and Poors and an investment grade rating of BBB- from Fitch Ratings.
This improvement should provide us a lower cost of capital on
planned expansions in our pipeline business;
    
    Restructuring the El Paso and EPEP revolving
credit facilities with improved terms and total capacities of $1.5 billion and $1.0
billion, respectively; and
    
    Completing our pipeline MLP initial public offering in November 2007 providing us a
lower cost of capital for further pipeline growth projects and
entering into a $750 million
revolving credit facility available to the MLP and non-recourse to El Paso.
 43




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##### Table of Contents



Results of Operations
 Overview
    2007
    
    
    2006
    
    
    2005(In millions)SegmentPipelines
    
    $
    1,265
    
    
    $
    1,187
    
    
    $
    924Exploration and Production
    
    
    909
    
    
    
    640
    
    
    
    696Marketing
    
    
    (202
    )
    
    
    (71
    )
    
    
    (837
    )Power
    
    
    (37
    )
    
    
    82
    
    
    
    (89
    )Field Services
    
    
    
    
    
    
    
    
    
    
    285Segment EBIT
    
    
    1,935
    
    
    
    1,838
    
    
    
    979Corporate and other
    
    
    (283
    )
    
    
    (88
    )
    
    
    (521
    )Consolidated EBIT
    
    
    1,652
    
    
    
    1,750
    
    
    
    458Interest and debt expense
    
    
    (994
    )
    
    
    (1,228
    )
    
    
    (1,295
    )Income taxes
    
    
    (222
    )
    
    
    9
    
    
    
    331Income (loss) from continuing operations
    
    
    436
    
    
    
    531
    
    
    
    (506
    )Discontinued operations, net of income taxes
    
    
    674
    
    
    
    (56
    )
    
    
    (96
    )Cumulative effect of accounting changes, net of income taxes
    
    
    
    
    
    
    
    
    
    
    (4
    )Net income (loss)
    
    $
    1,110
    
    
    $
    475
    
    
    $
    (606
    )
  44




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##### Table of Contents



Pipelines Segment
 Overview
  Percent of TotalType
    
    Description
    
    RevenuesReservation
    
    Reservation revenues are
from customers (referred
to as firm customers)
that reserve capacity on
our pipeline systems,
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.
    
    
    77Usage 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.
    
    
    23
    Percent of Total

    
    
    
    
    
    Percent of TotalBBtu/d

    
    Contracted Capacity

    
    Reservation Revenue

    
    Reservation Revenue(In millions)2008
    
    
    1,836
    
    
    
    8
    
    
    
    $   31
    
    
    
    22009
    
    
    2,539
    
    
    
    11
    
    
    
    170
    
    
    
    92010
    
    
    3,388
    
    
    
    14
    
    
    
    309
    
    
    
    172011
    
    
    2,755
    
    
    
    11
    
    
    
    152
    
    
    
    92012
    
    
    3,909
    
    
    
    16
    
    
    
    222
    
    
    
    122013 and beyond
    
    
    9,740
    
    
    
    40
    
    
    
    929
    
    
    
    51Total
    
    
    24,167
    
    
    
    100
    
    
    
    $1,813
    
    
    
    100
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##### Table of Contents



Summary of Operational and Financial Performance
    Project
    
    Anticipated In-Service Dates
    
    
    Estimated Cost
    
    
    FERC Approved(in millions)Cheyenne Plains Expansion
    
    
    July 2008
    
    
    $
    23
    
    
    YesCypress II/III
    
    
    May 2008/January 2011
    
    
    
    102
    
    
    YesEssex-Middlesex
    
    
    November 2008
    
    
    
    76
    
    
    YesSoutheast
Supply Header  Phase I
    
    
    June 2008
    
    
    
    137
    
    
    YesWIC Medicine Bow Expansion
    
    
    July 2008
    
    
    
    32
    
    
    YesHigh Plains Pipeline (50%)
    
    
    November 2008
    
    
    
    98
    
    
    NoCarthage Expansion
    
    
    May 2009
    
    
    
    39
    
    
    NoConcord Lateral Expansion
    
    
    November 2009
    
    
    
    21
    
    
    NoWIC Piceance Lateral Expansion
    
    
    4th Quarter 2009
    
    
    
    62
    
    
    NoTotem Storage (50%)
    
    
    July 2009
    
    
    
    60
    
    
    NoElba Expansion III and Elba Express
    
    
    2010-2013
    
    
    
    1,093
    
    
    YesSouth System
III and Southeast Supply Header  Phase II
    
    
    2010-2012
    
    
    
    319
    
    
    NoFGT Phase VIII Expansion (50%)
    
    
    2011
    
    
    
    1,050
    
    
    NoGulf LNG Clean Energy (50%)(1)
    
    
    2011
    
    
    
    787
    
    
    YesTotal Committed Expansion
Backlog
    
    
    
    
    
    $
    3,899
 
 (1)
    
    Includes approximately $294 million that we paid to acquire a 50 percent interest in this project. Other
Large Projects in Development.
 Operating Results
 2007
    
    
    2006
    
    
    2005(In millions, except volumes)Operating revenues
    
    $
    2,494
    
    
    $
    2,402
    
    
    $
    2,171Operating expenses
    
    
    (1,383
    )
    
    
    (1,339
    )
    
    
    (1,392
    )Operating income
    
    
    1,111
    
    
    
    1,063
    
    
    
    779Other income
    
    
    154
    
    
    
    124
    
    
    
    145EBIT
    
    $
    1,265
    
    
    $
    1,187
    
    
    $
    924Throughput volumes (BBtu/d)(1)TGP
    
    
    4,880
    
    
    
    4,534
    
    
    
    4,443EPNG and MPC
    
    
    4,216
    
    
    
    4,255
    
    
    
    4,214CIG, WIC and CPG
    
    
    4,906
    
    
    
    4,301
    
    
    
    3,734SNG
    
    
    2,345
    
    
    
    2,167
    
    
    
    1,984Other
    
    
    50
    
    
    
    50
    
    
    
    50Equity investments(2)
    
    
    1,734
    
    
    
    1,705
    
    
    
    1,645Total throughput
    
    
    18,131
    
    
    
    17,012
    
    
    
    16,070
 
 (1)
    
    Volumes exclude intrasegment activities.(2)
    
    Represents our proportional share. 46




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##### Table of Contents



2007 to 2006
    
    
    2006 to 2005Variance
    
    
    VarianceRevenue
    
    
    Expense
    
    
    Other
    
    
    EBIT
    
    
    Revenue
    
    
    Expense
    
    
    Other
    
    
    EBITImpact
    
    
    Impact
    
    
    Impact
    
    
    Impact
    
    
    Impact
    
    
    Impact
    
    
    Impact
    
    
    ImpactFavorable/(Unfavorable)(In millions)Reservation and usage revenues
    
    $
    31
    
    
    $
    
    
    
    $
    
    
    
    $
    31
    
    
    $
    128
    
    
    $
    
    
    
    $
    
    
    
    $
    128Expansions
    
    
    50
    
    
    
    (7
    )
    
    
    9
    
    
    
    52
    
    
    
    75
    
    
    
    (9
    )
    
    
    (10
    )
    
    
    56Gas not used in operations, revaluations,
processing revenues and other natural gas
sales
    
    
    3
    
    
    
    (16
    )
    
    
    
    
    
    
    (13
    )
    
    
    20
    
    
    
    38
    
    
    
    
    
    
    
    58Hurricanes Katrina and Rita
    
    
    
    
    
    
    12
    
    
    
    
    
    
    
    12
    
    
    
    
    
    
    
    (1
    )
    
    
    
    
    
    
    (1
    )Asset impairments
    
    
    
    
    
    
    4
    
    
    
    (2
    )
    
    
    2
    
    
    
    
    
    
    
    30
    
    
    
    
    
    
    
    30General and administrative expense
    
    
    
    
    
    
    (10
    )
    
    
    
    
    
    
    (10
    )
    
    
    
    
    
    
    52
    
    
    
    
    
    
    
    52Depreciation expense
    
    
    
    
    
    
    2
    
    
    
    
    
    
    
    2
    
    
    
    
    
    
    
    (19
    )
    
    
    
    
    
    
    (19
    )Operating costs (including pipeline integrity)
    
    
    
    
    
    
    (25
    )
    
    
    
    
    
    
    (25
    )
    
    
    
    
    
    
    (32
    )
    
    
    
    
    
    
    (32
    )Bankruptcy settlements
    
    
    
    
    
    
    (3
    )
    
    
    
    
    
    
    (3
    )
    
    
    15
    
    
    
    3
    
    
    
    
    
    
    
    18Equity earnings from Citrus
    
    
    
    
    
    
    
    
    
    
    19
    
    
    
    19
    
    
    
    
    
    
    
    
    
    
    
    (4
    )
    
    
    (4
    )Other(1)
    
    
    8
    
    
    
    (1
    )
    
    
    4
    
    
    
    11
    
    
    
    (7
    )
    
    
    (9
    )
    
    
    (7
    )
    
    
    (23
    )Total impact on EBIT
    
    $
    92
    
    
    $
    (44
    )
    
    $
    30
    
    
    $
    78
    
    
    $
    231
    
    
    $
    53
    
    
    $
    (21
    )
    
    $
    263
 
 (1)
    
    Consists of individually insignificant items on several of our pipeline systems. Reservation and Usage Revenues.
 
    
    an increase in throughput on our pipeline systems, primarily in the Rocky Mountains
and southern regions which increased due to new supply, colder weather and increased
transportation services to power plants;
    
    additional firm capacity sold in the south central region on
our TGP system; and
    
    increased rates on our CIG system effective October 2006 as a result of CIGs rate
settlement
   
    
    the expiration of reduced EPNG tariff rates effective December 31, 2005, to certain
customers under the terms of EPNGs FERC-approved system wide capacity allocation
proceeding;
    
    an increase in EPNGs tariff rates effective
January 1, 2006 as a result of its rate filing;
    
    the sales of additional firm capacity and higher realized rates on several of our pipeline
systems in 2006; and
    
    increased activity on our pipeline systems under various interruptible services
provided under their tariffs as a result of favorable market
conditions.
 Expansions.
 Projects Placed in Service in 2007 and 2006.
 47




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##### Table of Contents



Projects Placed in Service in 2008.
 Gas Not Used in Operations, Revaluations, Processing Revenues and Other Natural Gas Sales.
  Hurricanes Katrina and Rita.
 Asset Impairments.
 48




---



##### Table of Contents



General and Administrative Expenses.
 Depreciation Expense.
 Operating Costs (Including Pipeline Integrity).
 Bankruptcy Settlements.
 Equity Earnings from Citrus
 Regulatory Matters/Rate Cases.
 
    
    EPNG In August 2007, EPNG received approval of the settlement of its rate case
from the FERC. The settlement provides benefits for both EPNG and its customers for a
three year period ending December 31, 2008. Under the terms of the settlement, EPNG is
required to file a new rate case to be effective January 1, 2009. EPNG received approval
of its settlement from the FERC and refunded $115
million, with interest, in the fourth quarter of 2007. A final refund of $10
million was paid in January 2008.
    
    MPC MPCs primary customer is EPNG. In February 2007, MPC filed with the FERC a general rate case proposing a 33
percent decrease in its base tariff rates. No
new services were proposed. The new base rates were effective March 1, 2007. In December
2007, FERC approved an offer of settlement to resolve all issues in
the rate case. Under the settlement, MPC has a $4 million, third
party refund obligation for a previously accrued regulatory obligation.
 49




---



##### Table of Contents




    
    CIG/WIC  In August 2007, CIG filed a tariff change with the FERC to modify its
fuel recovery mechanism to recover all cost impacts, or flow through to shippers any
revenue impacts, of fuel imbalance revaluations and related gas balance items. CIG
currently experiences variability in cash flow and earnings under its fuel recovery
mechanism, but its earnings variability from price fluctuations will be
substantially reduced if the FERC approves the fuel tracker. This tariff filing was
protested by certain shippers and the FERC suspended the effective date to March 1, 2008
subject to the similar outcome of a technical conference on the proposed tariff change which was
held in November 2007. In September 2007, WIC filed a tariff change with the FERC.
This tariff filing was protested by certain shippers and the FERC suspended
the effective date to April 1, 2008, subject to the outcome of a technical conference on
the proposed tariff change, which was held in November 2007. Comments on these
proposals have been filed by various parties to the proceedings, but no further action
has yet been taken by the FERC relative to these proceedings.
 50




---



##### Table of Contents



Exploration and Production Segment
 Overview and Strategy
    
    
    Re-shaping our portfolio to provide greater opportunities to achieve 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.
   51




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##### Table of Contents



Significant Operational Factors Affecting the Year Ended December 31, 2007
 Production.
 2007
    
    2006
    
    2005United StatesOnshore
    
    
    374
    
    
    
    345
    
    
    
    300Texas Gulf Coast
    
    
    213
    
    
    
    187
    
    
    
    211Gulf of Mexico and south Louisiana
    
    
    191
    
    
    
    174
    
    
    
    179InternationalBrazil
    
    
    14
    
    
    
    24
    
    
    
    53Total Consolidated
    
    
    792
    
    
    
    730
    
    
    
    743Four Star
    
    
    70
    
    
    
    68
    
    
    
    24
 Onshore region
 Texas Gulf Coast region
 Gulf of Mexico and south Louisiana region
 Brazil
 Four
Star
 2007 Drilling Results
 Onshore.
 Texas Gulf Coast.
 Gulf of Mexico and south Louisiana.
 Brazil.
 Egypt.
 52




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##### Table of Contents



Cash Operating Costs.
 Reserve Replacement Costs/Reserve Replacement Ratio.
 Reserve replacement ratio
    
    Sum of reserve additions(1)Actual production for the corresponding period
 Reserve replacement costs/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 in Item 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.   53




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##### Table of Contents



2007
    
    2006
    
    2005($/Mcfe)DomesticReserve replacement costs, including acquisitions
    
    $
    3.26
    
    
    $
    3.92
    
    
    $
    3.02Reserve replacement costs, excluding acquisitions
    
    
    3.22
    
    
    
    3.94
    
    
    
    3.98WorldwideReserve replacement costs, including acquisitions
    
    $
    3.55
    
    
    $
    4.17
    
    
    $
    2.75Reserve replacement costs, excluding acquisitions
    
    
    3.79
    
    
    
    4.19
    
    
    
    3.19
 (% of Production)DomesticReserve replacement ratio, including acquisitions
    
    
    255
    %
    
    
    109
    %
    
    
    188
    %Reserve replacement ratio, excluding acquisitions
    
    
    129
    %
    
    
    108
    %
    
    
    79
    %WorldwideReserve replacement ratio, including acquisitions
    
    
    252
    %
    
    
    108
    %
    
    
    195
    %Reserve replacement ratio, excluding acquisitions
    
    
    129
    %
    
    
    107
    %
    
    
    93
    %
  Capital Expenditures.
 2007
    
    
    2006
    
    
    2005(in millions)Total oil and gas capital costs(1)
    
    $
    2,589
    
    
    $
    1,193
    
    
    $
    1,462Less: acquisition capital
    
    
    (1,178
    )
    
    
    (4
    )
    
    
    (651
    )Capital expenditures, excluding acquisitions
    
    $
    1,411
    
    
    $
    1,189
    
    
    $
    811
 
 (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 2008
  
    
    Average daily production volumes for the year of approximately 805 MMcfe/d to 860
MMcfe/d, which excludes approximately 65 MMcfe/d to 70 MMcfe/d from our equity investment in
Four Star.
    
    Capital expenditures, excluding acquisitions, of approximately $1.7 billion. While
approximately 80% of the Companys planned 2008 capital program is allocated to its domestic
program, we plan to spend approximately $350 million in international capital in 2008,
primarily in our Brazil exploration and development program. As part of our domestic
capital program, we will allocate a greater percentage of our capital to our Onshore and
Texas Gulf Coast regions in light of our announced divestiture plans.
    
    Average cash operating costs which include production costs, general and administrative
expenses and other expenses of approximately $1.75/Mcfe to $1.90/Mcfe for the year; and
    
    Depreciation, depletion and amortization rate of between $2.80/Mcfe and $3.20/Mcfe.
 54




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##### Table of Contents



Price Risk Management Activities
   Fixed Price
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    BasisSwaps(1)
    
    Floors(1)
    
    Ceilings(1)
    
    Swaps(1)(2)Average
    
    
    
    
    
    Average
    
    
    
    
    
    Average
    
    Texas Gulf Coast
    
    Onshore-Raton
    
    RockiesVolumes
    
    Price
    
    Volumes
    
    Price
    
    Volumes
    
    Price
    
    Volumes
    
    Avg. Price
    
    Volumes
    
    Avg. Price
    
    Volumes
    
    Avg. PriceNatural Gas2008
    
    
    33
    
    
    $
    7.65
    
    
    
    108
    
    
    $
    8.00
    
    
    
    108
    
    
    $
    10.80
    
    
    
    58
    
    
    $
    (0.33
    )
    
    
    26
    
    
    $
    (1.13
    )
    
    
    13
    
    
    $
    (1.37
    )2009
    
    
    5
    
    
    $
    3.56
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    15
    
    
    $
    (1.00
    )
    
    
    
    
    
    
    2010
    
    
    5
    
    
    $
    3.70
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2011-2012
    
    
    6
    
    
    $
    3.88
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Oil2008
    
    
    2,498
    
    
    $
    88.48
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
 
 (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 limit our exposure to differences between the NYMEX gas price and the price at the location where we
sell our gas. The average prices listed above are the amounts we will pay per MMBtu relative to the NYMEX price to lock-in these
locational differences.    55




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##### Table of Contents



Operating Results and Variance Analysis
  2007
    
    
    2006
    
    
    2005(In millions, except forVolumes and prices)Operating Revenues:Natural gas
    
    $
    1,764
    
    
    $
    1,406
    
    
    $
    1,420Oil, condensate and NGL
    
    
    494
    
    
    
    430
    
    
    
    371Other
    
    
    42
    
    
    
    18
    
    
    
    (4
    )Total operating revenues
    
    
    2,300
    
    
    
    1,854
    
    
    
    1,787Operating Expenses:Depreciation, depletion and amortization
    
    
    (780
    )
    
    
    (645
    )
    
    
    (612
    )Production costs
    
    
    (344
    )
    
    
    (331
    )
    
    
    (261
    )Cost of products and services
    
    
    (92
    )
    
    
    (87
    )
    
    
    (47
    )General and administrative expenses
    
    
    (185
    )
    
    
    (156
    )
    
    
    (185
    )Other
    
    
    (13
    )
    
    
    (10
    )
    
    
    (11
    )Total operating expenses
    
    
    (1,414
    )
    
    
    (1,229
    )
    
    
    (1,116
    )Operating income
    
    
    886
    
    
    
    625
    
    
    
    671Other income (1)
    
    
    23
    
    
    
    15
    
    
    
    25EBIT
    
    $
    909
    
    
    $
    640
    
    
    $
    696
 
 (1)
    
    Includes equity earnings from our investment in Four Star. Percent
    
    
    
    
    
    
    Percent2007
    
    
    Variance
    
    
    2006
    
    
    Variance
    
    
    2005Consolidated volumes, prices and costs per unit:Natural gasVolumes (MMcf)
    
    
    242,316
    
    
    
    10
    %
    
    
    220,402
    
    
    
    (1
    )%
    
    
    222,292Average realized prices including hedges ($/Mcf)
    
    $
    7.28
    
    
    
    14
    %
    
    $
    6.38
    
    
    
    
    %
    
    $
    6.39Average realized prices excluding hedges ($/Mcf)
    
    $
    6.53
    
    
    
    (2
    )%
    
    $
    6.64
    
    
    
    (12
    )%
    
    $
    7.53Average transportation costs ($/Mcf)
    
    $
    0.27
    
    
    
    17
    %
    
    $
    0.23
    
    
    
    28
    %
    
    $
    0.18Oil, condensate and NGLVolumes (MBbls)
    
    
    7,821
    
    
    
    2
    %
    
    
    7,686
    
    
    
    (6
    )%
    
    
    8,136Average
realized prices including hedges ($/Bbl)
    
    $
    63.11
    
    
    
    13
    %
    
    $
    55.90
    
    
    
    23
    %
    
    $
    45.60Average
realized prices excluding hedges ($/Bbl)
    
    $
    63.71
    
    
    
    13
    %
    
    $
    56.21
    
    
    
    21
    %
    
    $
    46.43Average transportation costs ($/Bbl)
    
    $
    0.81
    
    
    
    (1
    )%
    
    $
    0.82
    
    
    
    30
    %
    
    $
    0.63Total equivalent volumesMMcfe
    
    
    289,242
    
    
    
    9
    %
    
    
    266,518
    
    
    
    (2
    )%
    
    
    271,107MMcfe/d
    
    
    792
    
    
    
    8
    %
    
    
    730
    
    
    
    (2
    )%
    
    
    743Production costs and other cash operating costs ($/Mcfe)Average lease operating costs
    
    $
    0.88
    
    
    
    (7
    )%
    
    $
    0.95
    
    
    
    32
    %
    
    $
    0.72Average production taxes(1)
    
    
    0.31
    
    
    
    7
    %
    
    
    0.29
    
    
    
    21
    %
    
    
    0.24Total production costs
    
    $
    1.19
    
    
    
    (4
    )%
    
    $
    1.24
    
    
    
    29
    %
    
    $
    0.96Average general and administrative expenses
    
    $
    0.64
    
    
    
    8
    %
    
    $
    0.59
    
    
    
    (13
    )%
    
    $
    0.68Average taxes, other than production and income taxes
    
    $
    0.05
    
    
    
    67
    %
    
    $
    0.03
    
    
    
    
    %
    
    $
    0.03Total cash operating costs
    
    $
    1.88
    
    
    
    1
    %
    
    $
    1.86
    
    
    
    11
    %
    
    $
    1.67Depreciation, depletion and amortization ($/Mcfe)
    
    $
    2.70
    
    
    
    12
    %
    
    $
    2.42
    
    
    
    7
    %
    
    $
    2.26Unconsolidated affiliate volumes (Four Star)Natural gas (MMcf)
    
    
    19,380
    
    
    
    
    
    
    
    18,140
    
    
    
    
    
    
    
    6,689Oil, condensate and NGL (MBbls)
    
    
    1,015
    
    
    
    
    
    
    
    1,087
    
    
    
    
    
    
    
    359Total equivalent volumesMMcfe
    
    
    25,470
    
    
    
    
    
    
    
    24,663
    
    
    
    
    
    
    
    8,844MMcfe/d
    
    
    70
    
    
    
    
    
    
    
    68
    
    
    
    
    
    
    
    24
 
 (1)
    
    Production taxes include ad valorem and severance taxes. 56




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##### Table of Contents



Year Ended December 31, 2007 Compared to Year Ended December 31, 2006
  VarianceOperating
    
    
    OperatingRevenue
    
    
    Expense
    
    
    Other
    
    
    EBITFavorable/(Unfavorable)(In millions)Natural Gas RevenueLower natural gas prices in 2007
    
    $
    (26
    )
    
    $
    
    
    
    $
    
    
    
    $
    (26
    )Impact of hedges
    
    
    239
    
    
    
    
    
    
    
    
    
    
    
    239Higher volumes in 2007
    
    
    145
    
    
    
    
    
    
    
    
    
    
    
    145Oil, Condensate and NGL RevenueHigher oil, condensate, and NGL prices in 2007
    
    
    59
    
    
    
    
    
    
    
    
    
    
    
    59Impact of hedges
    
    
    (4
    )
    
    
    
    
    
    
    
    
    
    
    (4
    )Higher volumes in 2007
    
    
    7
    
    
    
    
    
    
    
    
    
    
    
    7Other RevenueChange in fair value of derivatives not designated as accounting hedges
    
    
    47
    
    
    
    
    
    
    
    
    
    
    
    47Other
    
    
    (21
    )
    
    
    
    
    
    
    
    
    
    
    (21
    )Depreciation, Depletion and Amortization ExpenseHigher depletion rate in 2007
    
    
    
    
    
    
    (82
    )
    
    
    
    
    
    
    (82
    )Higher production volumes in 2007
    
    
    
    
    
    
    (52
    )
    
    
    
    
    
    
    (52
    )Production CostsHigher lease operating costs in 2007
    
    
    
    
    
    
    (1
    )
    
    
    
    
    
    
    (1
    )Higher production taxes in 2007
    
    
    
    
    
    
    (12
    )
    
    
    
    
    
    
    (12
    )General and Administrative Expenses
    
    
    
    
    
    
    (29
    )
    
    
    
    
    
    
    (29
    )OtherEarnings from investment in Four Star
    
    
    
    
    
    
    
    
    
    
    2
    
    
    
    2Other
    
    
    
    
    
    
    (9
    )
    
    
    6
    
    
    
    (3
    )Total Variances
    
    $
    446
    
    
    $
    (185
    )
    
    $
    8
    
    
    $
    269
 Operating revenues.
 Other revenue.
 Depreciation, depletion and amortization expense.
 Production costs.
 General and administrative expenses.
 57




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##### 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 natural gas prices in 2006
    
    $
    (197
    )
    
    $
    
    
    
    $
    
    
    
    $
    (197
    )Impact of hedges
    
    
    197
    
    
    
    
    
    
    
    
    
    
    
    197Lower production volumes in 2006
    
    
    (14
    )
    
    
    
    
    
    
    
    
    
    
    (14
    )Oil, Condensate and NGL RevenueHigher oil, condensate, and NGL 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.
 General and administrative expenses.
 Other.
 58




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##### Table of Contents



Marketing Segment
  Contract Type
    
    Description
    
    Remaining ExposureMark-to-MarketProduction-related natural
gas and oil derivatives
    
    Option contracts with various
floor and ceiling prices
    
    Changes in natural gas and oil prices.Power contracts
    
    Pennsylvania-New Jersey-Maryland
(PJM) basis and installed
capacity positions.
    
    Changes in regional power prices and
installed capacity prices.PJM commodity contracts.
    
    Counterparty credit as commodity
positions are hedged at PJM west hub.Other natural gas contracts
    
    Fixed-price and index-priced,
physical delivery contracts;
fixed-for-float swaps.
    
    Counterparty credit as commodity
positions were flattened as a result
of transactions entered into in 2006
and 2007.AccrualTransportation-related 
natural gas contracts
    
    Pipeline capacity contracts.
    
    Locational differences in natural gas
prices which could affect our ability
to use the capacity to recover demand
charges. Exposure to future losses
reduced significantly due to
releasing or assigning capacity
related to Alliance and other
pipelines in 2006 and 2007.Long-term gas supply 
obligations
    
    Primarily four contracts with
delivery obligations up to 0.3
Bcf/d with expiration dates
ranging from 2011 to 2028.
    
    Index-priced contracts are exposed to
locational changes in natural gas
prices.
 59




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##### Table of Contents



Operating Results
 Overview.
 2007
    
    
    2006
    
    
    2005(In millions)Revenue by Significant Contract Type:Production-Related Natural Gas and Oil Derivative ContractsChanges in fair value of options and swaps
    
    $
    (89
    )
    
    $
    269
    
    
    $
    (436
    )Contracts Related to Legacy Trading Operations:Natural gas transportation-related natural gas contracts:Demand charges
    
    
    (98
    )
    
    
    (125
    )
    
    
    (156
    )Settlements, net of termination payments
    
    
    76
    
    
    
    (110
    )
    
    
    121Changes in fair value of other natural gas derivative contracts
    
    
    (31
    )
    
    
    (163
    )
    
    
    39Changes in fair value of power contracts
    
    
    (77
    )
    
    
    71
    
    
    
    (386
    )Other
    
    
    
    
    
    
    
    
    
    
    22Total revenues
    
    
    (219
    )
    
    
    (58
    )
    
    
    (796
    )Operating expenses
    
    
    (15
    )
    
    
    (33
    )
    
    
    (59
    )Operating loss
    
    
    (234
    )
    
    
    (91
    )
    
    
    (855
    )Other income, net
    
    
    32
    
    
    
    20
    
    
    
    18EBIT
    
    $
    (202
    )
    
    $
    (71
    )
    
    $
    (837
    )
   
    
    mark-to-market gains and losses on our production-related natural gas and oil derivative contracts
    
    the divestiture in 2006 of a significant portion of our natural gas portfolio
    
    a termination payment in 2006 of $188 million to a third party to assume our
Alliance transportation capacity obligations effective November 1, 2007
    
    losses in 2006 based on changes in the fair value of our other natural gas
derivative contracts including approximately $133 million of previously unrecorded losses
on our Midland Cogeneration Venture (MCV) supply agreement in conjunction with the sale
of our interest in that facility
    
    the divestitures in 2005 of our Cordova tolling agreement and a majority of the
contracts in our power portfolio
 Production-related Natural Gas and Oil Derivative Contracts
 Options contracts.
 Floors(1)
    
    Ceilings(1)Average
    
    
    
    
    
    AverageVolumes
    
    Price
    
    Volumes
    
    PriceNatural Gas 2009
    
    
    17
    
    
    $
    6.00
    
    
    
    17
    
    
    $
    8.75Oil 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. 60




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##### Table of Contents



Contracts Related to Legacy Trading Operations
 Natural gas transportation-related contracts.
 2007
    
    2006
    
    2005Alliance:Demand charges
    
    $
    56
    
    
    $
    64
    
    
    $
    65Recovery(1)
    
    
    48
    %
    
    
    59
    %
    
    
    93
    %Other:Demand charges
    
    $
    42
    
    
    $
    61
    
    
    $
    91Recovery
    
    
    100
    %
    
    
    68
    %
    
    
    69
    %
 
 (1)
    
    Excluded from this amount is the $188 million we paid in 2006 in conjunction with the sale of this contract. Other natural gas derivative contracts.
 Power Contracts.
  Other.
 61




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##### Table of Contents



Power Segment
 Overview.
 AmountArea
    
    (In millions)BrazilPorto Velho
    
    $
    275Manaus & Rio Negro
    
    
    57Pipeline projects
    
    
    138Asia & Central America
    
    
    78Total investment, guarantees and letters of credit
    
    $
    548
 Operating Results.
 2007
    
    
    2006
    
    
    2005(In millions)EBIT by Area:BrazilImpairments
    
    $
    (72
    )
    
    $
    
    
    
    $
    Other EBIT from operations
    
    
    51
    
    
    
    64
    
    
    
    55Other International PowerImpairments, net of gains (losses) on sales
    
    
    (1
    )
    
    
    (12
    )
    
    
    (45
    )Other EBIT from operations
    
    
    (1
    )
    
    
    (1
    )
    
    
    34Domestic PowerImpairments, net of gains (losses) on sales
    
    
    
    
    
    
    10
    
    
    
    (167
    )Favorable resolution of bankruptcy claim
    
    
    
    
    
    
    
    
    
    
    53Gain on sale of available-for-sale investment(1)
    
    
    
    
    
    
    47
    
    
    
    40Other(2)
    
    
    (14
    )
    
    
    (26
    )
    
    
    (59
    )EBIT
    
    $
    (37
    )
    
    $
    82
    
    
    $
    (89
    )
 
 (1)
    
    Related to the disposition of our shares of International Commodity Exchange in 2005 and 2006.(2)
    
    Consists of indirect expenses and general and administrative costs and includes $27 million of impairments and losses in 2005. Brazil.
 Other International Power.
 62




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##### Table of Contents





Domestic Power.


Field Services




Corporate and Other Expenses, Net




2007
    
    
    2006
    
    
    2005(In millions)Early extinguishment/exchange of debt
    
    $
    (291
    )
    
    $
    (26
    )
    
    $
    (29
    )Foreign currency fluctuations on Euro-denominated debt
    
    
    (8
    )
    
    
    (20
    )
    
    
    36Change in litigation, insurance and other reserves
    
    
    23
    
    
    
    (71
    )
    
    
    (490
    )Lease termination
    
    
    
    
    
    
    
    
    
    
    (27
    )Other
    
    
    (7
    )
    
    
    29
    
    
    
    (11
    )Total EBIT
    
    $
    (283
    )
    
    $
    (88
    )
    
    $
    (521
    )


Extinguishment of Debt.


Litigation, Insurance, and Other Reserves.


Interest and Debt Expense




63




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##### Table of Contents



Income Taxes
 Years Ended December 31,2007
    
    2006
    
    2005(In millions)Income taxes from continuing operations
    
    $
    222
    
    
    $
    (9
    )
    
    $
    (331
    )Effective tax rate
    
    
    34
    %
    
    
    (2
    )%
    
    
    40
    %
   Discontinued Operations
  Commitments and Contingencies
  64




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##### Table of Contents



Liquidity and Capital Resources
 Sources and Uses of Cash.
 Overview of Cash Flow Activities.
 2007
    
    
    2006(In billions)Cash Flow from OperationsContinuing operating activitiesIncome from continuing operations
    
    $
    0.4
    
    
    $
    0.5Loss on debt extinguishment
    
    
    0.3
    
    
    
    Other income adjustments
    
    
    1.4
    
    
    
    1.1Change in other assets and liabilities
    
    
    (0.3
    )
    
    
    0.2Total cash flow from operations
    
    $
    1.8
    
    
    $
    1.8Other Cash InflowsContinuing investing activitiesNet proceeds from the sale of assets and investments
    
    $
    0.1
    
    
    $
    0.7Net change in restricted cash and other
    
    
    
    
    
    
    0.20.1
    
    
    
    0.9Continuing financing activitiesNet proceeds from the issuance of long-term debt
    
    
    6.6
    
    
    
    0.4Contribution from discontinued operations
    
    
    3.4
    
    
    
    0.2Net proceeds from the issuance of common stock
    
    
    
    
    
    
    0.5Net proceeds from the issuance of minority interest in consolidated subsidiary
    
    
    0.5
    
    
    
    10.5
    
    
    
    1.1Total other cash inflows
    
    $
    10.6
    
    
    $
    2.0Cash OutflowsContinuing investing activitiesCapital expenditures
    
    $
    2.5
    
    
    $
    2.2Cash paid for acquisitions, net of cash acquired
    
    
    1.2
    
    
    
    3.7
    
    
    
    2.2Continuing financing activitiesPayments to retire long-term debt and other financing obligations
    
    
    8.9
    
    
    
    3.0Dividends and other
    
    
    0.1
    
    
    
    0.29.0
    
    
    
    3.2Total cash outflows
    
    $
    12.7
    
    
    $
    5.4Net change in cash
    
    $
    (0.3
    )
    
    $
    (1.6
    )
  (In billions)Proceeds from sale of ANR and related assets
    
    $
    3.7Payments to retire ANR debt obligations
    
    
    (0.3
    )Contribution from discontinued operations
    
    $
    3.4
 65




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##### Table of Contents



Credit Profile.
  Liquidity/Cash Flow Outlook.
  Total(In billions)PipelinesMaintenance
    
    $
    0.4Growth
    
    
    1.2Exploration and Production
    
    
    1.7Corporate
and other(1)
    
    
    0.1$
    3.4
 
 (1)
    
    Relates primarily to building renovations at our corporate facilities. Factors That Could Impact Our Future Liquidity.
 66




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##### Table of Contents



Price Risk Management Activities and Cash Margining Requirements.
 Fixed Price
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    BasisSwaps(1)
    
    Floors(1)
    
    Ceilings(1)
    
    Swaps(1)(2)Average
    
    
    
    
    
    Average
    
    
    
    
    
    Average
    
    Texas Gulf Coast
    
    Onshore-Raton
    
    RockiesVolumes
    
    Price
    
    Volumes
    
    Price
    
    Volumes
    
    Price
    
    Volumes
    
    Avg. Price
    
    Volumes
    
    Avg. Price
    
    Volumes
    
    Avg. PriceNatural Gas2008
    
    
    33
    
    
    $
    7.65
    
    
    
    108
    
    
    $
    8.00
    
    
    
    108
    
    
    $
    10.80
    
    
    
    58
    
    
    $
    (0.33
    )
    
    
    26
    
    
    $
    (1.13
    )
    
    
    13
    
    
    $
    (1.37
    )2009
    
    
    5
    
    
    $
    3.56
    
    
    
    17
    
    
    $
    6.00
    
    
    
    17
    
    
    $
    8.75
    
    
    
    
    
    
    
    
    
    
    
    15
    
    
    $
    (1.00
    )
    
    
    
    
    
    
    2010
    
    
    5
    
    
    $
    3.70
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2011-2012
    
    
    6
    
    
    $
    3.88
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Oil2008
    
    
    2,498
    
    
    $
    88.48
    
    
    
    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 limit our exposure to differences between the NYMEX
gas price and the price at the location where we sell our gas. The average prices listed above
are the amounts we will pay per MMBtu relative to the NYMEX price to lock-in these
locational price differences.    67




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##### Table of Contents



Off-Balance Sheet Arrangements
  Guarantees
    Letters of Credit
  Interests in Variable Interest Entities
  68




---



##### 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
    
    $
    331
    
    
    $
    1,346
    
    
    $
    2,718
    
    
    $
    8,452
    
    
    $
    12,847Interest
    
    
    914
    
    
    
    1,677
    
    
    
    1,490
    
    
    
    8,051
    
    
    
    12,132Liabilities from commodity-based derivative contracts
    
    
    267
    
    
    
    431
    
    
    
    319
    
    
    
    178
    
    
    
    1,195Other contractual liabilities
    
    
    56
    
    
    
    68
    
    
    
    26
    
    
    
    54
    
    
    
    204Operating leases
    
    
    14
    
    
    
    23
    
    
    
    14
    
    
    
    29
    
    
    
    80Other contractual commitments and purchase obligations:Transportation and storage
    
    
    26
    
    
    
    43
    
    
    
    26
    
    
    
    100
    
    
    
    195Other
    
    
    561
    
    
    
    91
    
    
    
    31
    
    
    
    26
    
    
    
    709Total contractual obligations
    
    $
    2,169
    
    
    $
    3,679
    
    
    $
    4,624
    
    
    $
    16,890
    
    
    $
    27,362
 Long Term Financing Obligations (Principal and Interest).
 Liabilities from Commodity-Based Derivative Contracts.
 Other Contractual Liabilities.
 Operating Leases.
 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 these
liabilities are not contractually fixed as to timing and amount.
 69




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##### Table of Contents



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 hedgesNon-exchange traded positionsAssets
    
    $
    65
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    65Liabilities
    
    
    (19
    )
    
    
    (42
    )
    
    
    (27
    )
    
    
    
    
    
    
    
    
    
    
    (88
    )Total derivatives designated as hedges
    
    
    46
    
    
    
    (42
    )
    
    
    (27
    )
    
    
    
    
    
    
    
    
    
    
    (23
    )Other commodity-based derivativesExchange-traded positions(1)Liabilities
    
    
    
    
    
    
    (15
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (15
    )Non-exchange traded positionsAssets
    
    
    48
    
    
    
    72
    
    
    
    82
    
    
    
    29
    
    
    
    7
    
    
    
    238Liabilities
    
    
    (248
    )
    
    
    (374
    )
    
    
    (292
    )
    
    
    (174
    )
    
    
    (4
    )
    
    
    (1,092
    )Total other commodity-based derivatives
    
    
    (200
    )
    
    
    (317
    )
    
    
    (210
    )
    
    
    (145
    )
    
    
    3
    
    
    
    (869
    )Total commodity-based derivatives
    
    $
    (154
    )
    
    $
    (359
    )
    
    $
    (237
    )
    
    $
    (145
    )
    
    $
    3
    
    
    $
    (892
    )
 
 (1)
    
    These positions are traded on active exchanges such as the New York Mercantile Exchange, the International Petroleum Exchange and the London Clearinghouse.  Other
    
    
    TotalDerivatives
    
    
    Commodity-
    
    
    Commodity-Designated
    
    
    Based
    
    
    Basedas Hedges
    
    
    Derivatives
    
    
    Derivatives(In millions)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
    )Fair value of contract settlements during the period(1)
    
    
    (109
    )
    
    
    (224
    )
    
    
    (333
    )Change in fair value of contracts
    
    
    4
    
    
    
    (211
    )
    
    
    (207
    )Assignment of contracts
    
    
    
    
    
    
    18
    
    
    
    18Option premiums paid(2)
    
    
    21
    
    
    
    4
    
    
    
    25Net change in contracts outstanding during the period
    
    
    (84
    )
    
    
    (413
    )
    
    
    (497
    )Fair value of contracts outstanding at December 31, 2007
    
    $
    (23
    )
    
    $
    (869
    )
    
    $
    (892
    )
 
 (1)
    
    In 2006 includes derivative contracts
sold/terminated. In 2007, we settled derivative assets
of approximately $381 million by applying the related cash
margin we held against amounts due to us under those
contracts.(2)
    
    Amounts are net of premiums received. Fair Value of Contract Settlements.
 70




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Changes in Fair Value of Contracts.
 Assignment of Contracts.
 Designation and Reclassifications of Hedges.
 Critical Accounting Estimates
  Accounting for Natural Gas and Oil Producing Activities.
    71




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##### Table of Contents



Accounting for Legal and Environmental Reserves, Guarantees and Indemnifications.
  Off Balance Sheet Arrangements
 Accounting for Pension and Other Postretirement Benefits.
 72




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##### Table of Contents



Pension Benefits
    
    Other Postretirement BenefitsChange in Net
    
    
    
    
    
    Change in NetAsset and Pretax
    
    
    
    
    
    Asset and PretaxAccumulated Other
    
    
    
    
    
    Accumulated OtherNet Benefit
    
    Comprehensive
    
    Net Benefit
    
    ComprehensiveExpense (Income)
    
    Income
    
    Expense (Income)
    
    IncomeOne percent increase in:Discount rates
    
    $
    (11
    )
    
    $
    170
    
    
    $
    
    
    
    $
    36Expected return on plan assets
    
    
    (23
    )
    
    
    
    
    
    
    (3
    )
    
    
    Rate of compensation increase
    
    
    2
    
    
    
    (4
    )
    
    
    
    
    
    
    Health care cost trends
    
    
    
    
    
    
    
    
    
    
    1
    
    
    
    (13
    )One percent decrease in:Discount rates
    
    $
    13
    
    
    $
    (201
    )
    
    $
    
    
    
    $
    (40
    )Expected return on plan assets(1)
    
    
    23
    
    
    
    
    
    
    
    3
    
    
    
    Rate of compensation increase
    
    
    (2
    )
    
    
    3
    
    
    
    
    
    
    
    Health care cost trends
    
    
    
    
    
    
    
    
    
    
    (1
    )
    
    
    12
 
 (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.   Change inAccrued LiabilityOne percent increase in:Discount rates
    
    $
    (35
    )Health care cost trends
    
    
    38One percent decrease in:Discount rates
    
    $
    39Health care cost trends
    
    
    (33
    )
 73




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##### Table of Contents



Price Risk Management Activities.
  10 Percent Increase
    
    
    10 Percent DecreaseFair Value
    
    
    Fair Value
    
    
    Change
    
    
    Fair Value
    
    
    Change(In millions)Derivatives designated as hedges
    
    $
    (23
    )
    
    $
    (117
    )
    
    $
    (94
    )
    
    $
    76
    
    
    $
    99Other commodity-based derivatives
    
    
    (869
    )
    
    
    (910
    )
    
    
    (41
    )
    
    
    (828
    )
    
    
    41Total
    
    $
    (892
    )
    
    $
    (1,027
    )
    
    $
    (135
    )
    
    $
    (752
    )
    
    $
    140
  Change in Discount Rate1 Percent Increase
    
    
    1 Percent DecreaseFair Value
    
    
    Fair Value
    
    
    Change
    
    
    Fair Value
    
    
    Change(In millions)Derivatives designated as hedges
    
    $
    (23
    )
    
    $
    (21
    )
    
    $
    2
    
    
    $
    (25
    )
    
    $
    (2
    )Other commodity-based derivatives
    
    
    (869
    )
    
    
    (846
    )
    
    
    23
    
    
    
    (894
    )
    
    
    (25
    )Total
    
    $
    (892
    )
    
    $
    (867
    )
    
    $
    25
    
    
    $
    (919
    )
    
    $
    (27
    )
 Fair Value Measurements
 Deferred Taxes and Uncertain Income Tax Positions.
 Valuation Allowance.
 Uncertain Tax Positions.
 74




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##### Table of Contents



Undistributed
Earnings of Foreign Investees and Certain Unconsolidated Affiliates.
  Asset and Investment Impairments.
 New Accounting Pronouncements Issued But Not Yet Adopted
 New Accounting
Pronouncements Issued But Not Yet Adopted.
 75




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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, affecting gas not used in the operations of our
Pipelines segment and affecting the fair value of our natural gas and oil derivative
contracts held in our Marketing segment;
    
    Natural gas locational price differences change, affecting our ability to optimize
pipeline transportation capacity contracts held in our Marketing segment; and
    
    Electricity price changes and locational pricing changes, affecting the value of
our 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; and
    
    Weakening or strengthening of the U.S. dollar relative to the Brazilian real and
the Mexican peso can affect the revenues and expenses generated by our foreign pipeline,
exploration and production, and power operations.
  
    
    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.
  76




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Commodity Price Risk
 Production-Related Derivatives
  10 Percent Increase
    
    10 Percent DecreaseFair Value
    
    Fair Value
    
    (Decrease)
    
    Fair Value
    
    IncreaseImpact of changes
in commodity prices
on
production-related
derivative
instrumentsDecember 31, 2007
    
    $
    (64
    )
    
    $
    (181
    )
    
    $
    (117
    )
    
    $
    58
    
    
    $
    122December 31, 2006
    
    $
    124
    
    
    $
    (9
    )
    
    $
    (133
    )
    
    $
    264
    
    
    $
    140
 Other Commodity-Based Derivatives
   77




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Interest Rate Risk
  December 31, 2007
    
    December 31, 2006Expected Fiscal Year of Maturity of Carrying Amounts
    
    
    
    
    
    Fair
    
    Carrying
    
    Fair2008
    
    2009
    
    2010
    
    2011
    
    2012
    
    Thereafter
    
    Total
    
    Value
    
    Amounts
    
    Value(In millions)Long-term debt and
other obligations,
including current
portion  fixed rate.
    
    $
    318
    
    
    $
    1,097
    
    
    $
    236
    
    
    $
    621
    
    
    $
    425
    
    
    $
    8,248
    
    
    $
    10,945
    
    
    $
    11,244
    
    
    $
    14,093
    
    
    $
    14,891Average interest rate
    
    
    6.2
    %
    
    
    6.7
    %
    
    
    6.1
    %
    
    
    6.4
    %
    
    
    7.3
    %
    
    
    7.2
    %Long-term debt and
other obligations,
including current
portion  variable
rate
    
    $
    13
    
    
    $
    14
    
    
    $
    15
    
    
    $
    16
    
    
    $
    1,648
    
    
    $
    163
    
    
    $
    1,869
    
    
    $
    1,869
    
    
    $
    596
    
    
    $
    596Average interest rate
    
    
    6.3
    %
    
    
    6.3
    %
    
    
    6.3
    %
    
    
    6.3
    %
    
    
    5.0
    %
    
    
    6.3
    %
 Foreign Currency Exchange Rate Risk
      
 78




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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 Index
  PageManagements Annual Report on Internal Control over Financial Reporting
    
    
    80Reports of Independent Registered Public Accounting Firms
    
    
    81Consolidated Statements of Income
    
    
    86Consolidated Balance Sheets
    
    
    87Consolidated Statements of Cash Flows
    
    
    89Consolidated Statements of Stockholders Equity
    
    
    90Consolidated Statements of Comprehensive Income
    
    
    91Notes to Consolidated Financial Statements
    
    
    921. Basis of Presentation and Significant Accounting Policies
    
    
    922. Divestitures
    
    
    983. Other Income and Other Expenses
    
    
    1014. Income Taxes
    
    
    1015. Earnings Per Share
    
    
    1046. Fair Value of Financial Instruments
    
    
    1047. Price Risk Management Activities
    
    
    1058. Regulatory Assets and Liabilities
    
    
    1089. Other Assets and Liabilities
    
    
    10810. Property, Plant and Equipment
    
    
    10911. Debt, Other Financing Obligations and Credit Facilities
    
    
    11012. Commitments and Contingencies
    
    
    11513. Retirement Benefits
    
    
    12014.
Stockholders Equity and Minority Interest
    
    
    12315. Stock-Based Compensation
    
    
    12416. Business Segment Information
    
    
    12617. Investments in, Earnings from and Transactions with Unconsolidated Affiliates
    
    
    130Supplemental Financial InformationSupplemental Selected Quarterly Financial Information (Unaudited)
    
    
    134Supplemental Natural Gas and Oil Operations (Unaudited)
    
    
    135Financial Statement ScheduleSchedule II  Valuation and Qualifying Accounts
    
    
    142
 79




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##### 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
 80




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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
    Accounting for Uncertainty in
Income Taxes, an interpretation of FASB Statement No. 109, Employers Accounting for
Defined Benefit Pension and Other Postretirement Plans - An Amendment of FASB Statements No. 87, 88, 106,
and 132(R), Share-Based Payment
  /s/  Ernst & Young LLP 
 81




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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON INTERNAL CONTROL OVER
FINANCIAL REPORTING
 
       /s/  Ernst & Young LLP 
 82




---



##### Table of Contents



Report of Independent Registered Public Accounting Firm
 
  Accounting for Conditional Asset Retirement Obligations,




---



##### Table of Contents



Report of Independent Registered Public Accounting Firm
    PricewaterhouseCoopers LLP




---



##### Table of Contents



Report of Independent Registered Public Accounting Firm




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##### Table of Contents



EL PASO CORPORATION
 
 CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per common share amounts)
 Year Ended December 31,2007
    
    
    2006
    
    
    2005Operating revenuesPipelines
    
    $
    2,494
    
    
    $
    2,402
    
    
    $
    2,171Exploration and Production
    
    
    2,300
    
    
    
    1,854
    
    
    
    1,787Marketing
    
    
    (219
    )
    
    
    (58
    )
    
    
    (796
    )Power
    
    
    
    
    
    
    6
    
    
    
    82Field Services
    
    
    
    
    
    
    
    
    
    
    123Corporate and eliminations
    
    
    73
    
    
    
    77
    
    
    
    (8
    )4,648
    
    
    
    4,281
    
    
    
    3,359Operating expensesCost of products and services
    
    
    245
    
    
    
    238
    
    
    
    245Operation and maintenance
    
    
    1,333
    
    
    
    1,337
    
    
    
    1,935Depreciation, depletion and amortization
    
    
    1,176
    
    
    
    1,047
    
    
    
    1,006Taxes, other than income taxes
    
    
    249
    
    
    
    232
    
    
    
    2343,003
    
    
    
    2,854
    
    
    
    3,420Operating income (loss)
    
    
    1,645
    
    
    
    1,427
    
    
    
    (61
    )Earnings from unconsolidated affiliates
    
    
    101
    
    
    
    145
    
    
    
    281Loss on debt extinguishment
    
    
    (291
    )
    
    
    (26
    )
    
    
    (29
    )Other income
    
    
    214
    
    
    
    245
    
    
    
    285Other expenses
    
    
    (11
    )
    
    
    (40
    )
    
    
    (17
    )Minority interest
    
    
    (6
    )
    
    
    (1
    )
    
    
    (1
    )Interest and debt expense
    
    
    (994
    )
    
    
    (1,228
    )
    
    
    (1,295
    )Income (loss) before income taxes from continuing operations
    
    
    658
    
    
    
    522
    
    
    
    (837
    )Income taxes
    
    
    222
    
    
    
    (9
    )
    
    
    (331
    )Income (loss) from continuing operations
    
    
    436
    
    
    
    531
    
    
    
    (506
    )Discontinued operations, net of income taxes
    
    
    674
    
    
    
    (56
    )
    
    
    (96
    )Cumulative effect of accounting changes, net of income taxes
    
    
    
    
    
    
    
    
    
    
    (4
    )Net income (loss)
    
    
    1,110
    
    
    
    475
    
    
    
    (606
    )Preferred stock dividends
    
    
    37
    
    
    
    37
    
    
    
    27Net income (loss) available to common stockholders
    
    $
    1,073
    
    
    $
    438
    
    
    $
    (633
    )Basic earnings (loss) per common shareIncome (loss) from continuing operations
    
    $
    0.57
    
    
    $
    0.73
    
    
    $
    (0.82
    )Discontinued operations, net of income taxes
    
    
    0.97
    
    
    
    (0.08
    )
    
    
    (0.15
    )Cumulative effect of accounting changes, net of income taxes
    
    
    
    
    
    
    
    
    
    
    (0.01
    )Net income (loss) per common share
    
    $
    1.54
    
    
    $
    0.65
    
    
    $
    (0.98
    )Diluted earnings (loss) per common shareIncome (loss) from continuing operations
    
    $
    0.57
    
    
    $
    0.72
    
    
    $
    (0.82
    )Discontinued operations, net of income taxes
    
    
    0.96
    
    
    
    (0.08
    )
    
    
    (0.15
    )Cumulative effect of accounting changes, net of income taxes
    
    
    
    
    
    
    
    
    
    
    (0.01
    )Net income (loss) per common share
    
    $
    1.53
    
    
    $
    0.64
    
    
    $
    (0.98
    )
  86




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EL PASO CORPORATION
 
 CONSOLIDATED BALANCE SHEETS
(In millions, except share amounts)
 December 31,2007
    
    
    2006ASSETSCurrent assetsCash and cash equivalents
    
    $
    285
    
    
    $
    537Accounts and notes receivableCustomer, net of allowance of $17 in 2007 and $28 in 2006
    
    
    468
    
    
    
    516Affiliates
    
    
    196
    
    
    
    192Other
    
    
    201
    
    
    
    495Inventory
    
    
    131
    
    
    
    115Assets from price risk management activities
    
    
    113
    
    
    
    436Assets held for sale and of discontinued operations
    
    
    
    
    
    
    4,161Deferred income taxes
    
    
    191
    
    
    
    478Other
    
    
    127
    
    
    
    237Total current assets
    
    
    1,712
    
    
    
    7,167Property, plant and equipment, at costPipelines
    
    
    16,750
    
    
    
    15,672Natural gas and oil properties, at full cost
    
    
    19,048
    
    
    
    16,572Other
    
    
    530
    
    
    
    56636,328
    
    
    
    32,810Less accumulated depreciation, depletion and amortization
    
    
    16,974
    
    
    
    16,132Total property, plant and equipment, net
    
    
    19,354
    
    
    
    16,678Other assetsInvestments in unconsolidated affiliates
    
    
    1,614
    
    
    
    1,707Assets from price risk management activities
    
    
    302
    
    
    
    414Other
    
    
    1,597
    
    
    
    1,2953,513
    
    
    
    3,416Total assets
    
    $
    24,579
    
    
    $
    27,261
  87




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##### Table of Contents



EL PASO CORPORATION
 CONSOLIDATED BALANCE SHEETS
(In millions, except share amounts)
 December 31,2007
    
    
    2006LIABILITIES AND STOCKHOLDERS EQUITYCurrent liabilitiesAccounts payableTrade
    
    $
    460
    
    
    $
    478Affiliates
    
    
    5
    
    
    
    3Other
    
    
    502
    
    
    
    569Short-term financing obligations, including current maturities
    
    
    331
    
    
    
    1,360Liabilities from price risk management activities
    
    
    267
    
    
    
    278Liabilities of discontinued operations
    
    
    
    
    
    
    1,817Margin deposits held by us
    
    
    20
    
    
    
    344Accrued interest
    
    
    195
    
    
    
    269Other
    
    
    633
    
    
    
    1,033Total current liabilities
    
    
    2,413
    
    
    
    6,151Long-term financing obligations, less current maturities
    
    
    12,483
    
    
    
    13,329OtherLiabilities from price risk management activities
    
    
    931
    
    
    
    924Deferred income taxes
    
    
    1,157
    
    
    
    950Other
    
    
    1,750
    
    
    
    1,6903,838
    
    
    
    3,564Commitments and contingencies (Note 12)Minority interests
    
    
    565
    
    
    
    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 709,192,605 shares in 2007 and 705,833,206 shares in 2006
    
    
    2,128
    
    
    
    2,118Additional paid-in capital
    
    
    4,699
    
    
    
    4,804Accumulated deficit
    
    
    (1,834
    )
    
    
    (2,940
    )Accumulated other comprehensive loss
    
    
    (272
    )
    
    
    (343
    )Treasury stock (at cost); 8,656,095 shares in 2007 and 8,715,288 shares in 2006
    
    
    (191
    )
    
    
    (203
    )Total stockholders equity
    
    
    5,280
    
    
    
    4,186Total liabilities and stockholders equity
    
    $
    24,579
    
    
    $
    27,261
  88




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##### Table of Contents



EL PASO CORPORATION
 
 CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
 Year Ended December 31,2007
    
    
    2006
    
    
    2005Cash flows from operating activitiesNet income (loss)
    
    $
    1,110
    
    
    $
    475
    
    
    $
    (606
    )Less income (loss) from discontinued operations, net of income taxes
    
    
    674
    
    
    
    (56
    )
    
    
    (96
    )Net income (loss) before discontinued operations
    
    
    436
    
    
    
    531
    
    
    
    (510
    )Adjustments to reconcile net income (loss) to net cash from operating activitiesDepreciation, depletion and amortization
    
    
    1,176
    
    
    
    1,047
    
    
    
    1,006Deferred income tax expense (benefit)
    
    
    182
    
    
    
    (20
    )
    
    
    (303
    )Earnings from unconsolidated affiliates, adjusted for cash distributions
    
    
    88
    
    
    
    (6
    )
    
    
    (78
    )Loss on debt extinguishment
    
    
    291
    
    
    
    26
    
    
    
    29Other non-cash income items
    
    
    (25
    )
    
    
    72
    
    
    
    401Asset and liability changesAccounts and notes receivable
    
    
    213
    
    
    
    344
    
    
    
    122Change in price risk management activities, net
    
    
    (69
    )
    
    
    (420
    )
    
    
    325Accounts payable
    
    
    (67
    )
    
    
    (382
    )
    
    
    (118
    )Change in margin and other deposits
    
    
    90
    
    
    
    911
    
    
    
    (679
    )Western Energy Settlement liability
    
    
    
    
    
    
    
    
    
    
    (395
    )Other asset changes
    
    
    (150
    )
    
    
    (179
    )
    
    
    177Other liability changes
    
    
    (327
    )
    
    
    (100
    )
    
    
    (10
    )Cash provided by (used in) continuing activities
    
    
    1,838
    
    
    
    1,824
    
    
    
    (33
    )Cash provided by (used in) discontinued activities
    
    
    (33
    )
    
    
    279
    
    
    
    301Net cash provided by operating activities
    
    
    1,805
    
    
    
    2,103
    
    
    
    268Cash flows from investing activitiesCapital expenditures
    
    
    (2,495
    )
    
    
    (2,164
    )
    
    
    (1,474
    )Cash paid for acquisitions, net of cash acquired
    
    
    (1,197
    )
    
    
    
    
    
    
    (1,140
    )Net proceeds from the sale of assets and investments
    
    
    106
    
    
    
    673
    
    
    
    1,424Net change in restricted cash
    
    
    33
    
    
    
    129
    
    
    
    (57
    )Other
    
    
    3
    
    
    
    23
    
    
    
    204Cash used in continuing activities
    
    
    (3,550
    )
    
    
    (1,339
    )
    
    
    (1,043
    )Cash provided by discontinued activities
    
    
    3,660
    
    
    
    185
    
    
    
    542Net cash provided by (used in) investing activities
    
    
    110
    
    
    
    (1,154
    )
    
    
    (501
    )Cash flows from financing activitiesNet proceeds from issuance of long-term debt
    
    
    6,624
    
    
    
    375
    
    
    
    1,620Payments to retire long-term debt and other financing obligations
    
    
    (8,902
    )
    
    
    (3,024
    )
    
    
    (1,491
    )Net proceeds from issuance of minority interest in consolidated subsidiary
    
    
    538
    
    
    
    
    
    
    
    Net proceeds from the issuance of common stock
    
    
    
    
    
    
    500
    
    
    
    Dividends paid
    
    
    (149
    )
    
    
    (145
    )
    
    
    (121
    )Net proceeds from issuance of preferred stock
    
    
    
    
    
    
    
    
    
    
    723Payments to minority interest  holders
    
    
    
    
    
    
    (5
    )
    
    
    (306
    )Contributions from discontinued operations
    
    
    3,344
    
    
    
    232
    
    
    
    666Other
    
    
    5
    
    
    
    (13
    )
    
    
    Cash provided by (used in) continuing activities
    
    
    1,460
    
    
    
    (2,080
    )
    
    
    1,091Cash used in discontinued activities
    
    
    (3,627
    )
    
    
    (464
    )
    
    
    (843
    )Net cash provided by (used in) financing activities
    
    
    (2,167
    )
    
    
    (2,544
    )
    
    
    248Change in cash and cash equivalents
    
    
    (252
    )
    
    
    (1,595
    )
    
    
    15Cash and cash equivalentsBeginning of period
    
    
    537
    
    
    
    2,132
    
    
    
    2,117End of period
    
    $
    285
    
    
    $
    537
    
    
    $
    2,132Supplemental cash flow information related to continuing operationsInterest paid, net of amounts capitalized
    
    $
    1,054
    
    
    $
    1,217
    
    
    $
    1,238Income tax payments
    
    
    34
    
    
    
    77
    
    
    
    11
  89




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##### Table of Contents

\

EL PASO CORPORATION
 
 CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
(In millions, except per share amounts)
 Year Ended December 31,2007
    
    
    2006
    
    
    2005Shares
    
    
    Amount
    
    
    Shares
    
    
    Amount
    
    
    Shares
    
    
    AmountPreferred stock, $0.01 par value:Balance at beginning of year
    
    
    1
    
    
    $
    750
    
    
    
    1
    
    
    $
    750
    
    
    
    
    
    
    $
    Equity offering
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1
    
    
    
    750Balance at end of year
    
    
    1
    
    
    
    750
    
    
    
    1
    
    
    
    750
    
    
    
    1
    
    
    
    750Common stock, $3.00 par value:Balance at beginning of year
    
    
    706
    
    
    
    2,118
    
    
    
    667
    
    
    
    2,001
    
    
    
    651
    
    
    
    1,953Exchange of equity security units
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    14
    
    
    
    41Equity offering
    
    
    
    
    
    
    
    
    
    
    36
    
    
    
    107
    
    
    
    
    
    
    
    Other, net
    
    
    3
    
    
    
    10
    
    
    
    3
    
    
    
    10
    
    
    
    2
    
    
    
    7Balance at end of year
    
    
    709
    
    
    
    2,128
    
    
    
    706
    
    
    
    2,118
    
    
    
    667
    
    
    
    2,001Additional paid-in capital:Balance at beginning of year
    
    
    
    
    
    
    4,804
    
    
    
    
    
    
    
    4,592
    
    
    
    
    
    
    
    4,538Equity offering
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    393
    
    
    
    
    
    
    
    Dividends
    
    
    
    
    
    
    (149
    )
    
    
    
    
    
    
    (147
    )
    
    
    
    
    
    
    (131
    )Exchange of equity security units
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    230Other, including stock-based compensation
    
    
    
    
    
    
    44
    
    
    
    
    
    
    
    (34
    )
    
    
    
    
    
    
    (45
    )Balance at end of year
    
    
    
    
    
    
    4,699
    
    
    
    
    
    
    
    4,804
    
    
    
    
    
    
    
    4,592Accumulated deficit:Balance at beginning of year
    
    
    
    
    
    
    (2,940
    )
    
    
    
    
    
    
    (3,415
    )
    
    
    
    
    
    
    (2,809
    )Net income (loss)
    
    
    
    
    
    
    1,110
    
    
    
    
    
    
    
    475
    
    
    
    
    
    
    
    (606
    )Cumulative
effect of adopting of
FIN No. 48
    
    
    
    
    
    
    (4
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Balance at end of year
    
    
    
    
    
    
    (1,834
    )
    
    
    
    
    
    
    (2,940
    )
    
    
    
    
    
    
    (3,415
    )Accumulated other comprehensive income (loss):Balance at beginning of year
    
    
    
    
    
    
    (343
    )
    
    
    
    
    
    
    (332
    )
    
    
    
    
    
    
    1Other comprehensive income (loss)
    
    
    
    
    
    
    80
    
    
    
    
    
    
    
    380
    
    
    
    
    
    
    
    (333
    )Cumulative
effect of adopting SFAS No. 158, net of income tax of $4 in 2007
and $210 in 2006
    
    
    
    
    
    
    (9
    )
    
    
    
    
    
    
    (391
    )
    
    
    
    
    
    
    Balance at end of year
    
    
    
    
    
    
    (272
    )
    
    
    
    
    
    
    (343
    )
    
    
    
    
    
    
    (332
    )Treasury stock, at cost:Balance at beginning of year
    
    
    (9
    )
    
    
    (203
    )
    
    
    (8
    )
    
    
    (190
    )
    
    
    (8
    )
    
    
    (225
    )Stock-based and other compensation
    
    
    
    
    
    
    12
    
    
    
    (1
    )
    
    
    (13
    )
    
    
    
    
    
    
    35Balance at end of year
    
    
    (9
    )
    
    
    (191
    )
    
    
    (9
    )
    
    
    (203
    )
    
    
    (8
    )
    
    
    (190
    )Unamortized compensation:Balance at beginning of year
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (17
    )
    
    
    
    
    
    
    (20
    )Stock-based compensation
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3Adoption of SFAS No. 123(R)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    17
    
    
    
    
    
    
    
    Balance at end of year
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (17
    )Total stockholders equity
    
    
    700
    
    
    $
    5,280
    
    
    
    697
    
    
    $
    4,186
    
    
    
    659
    
    
    $
    3,389
  90




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##### Table of Contents



EL PASO CORPORATION
 
 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In millions)
 Year Ended December 31,2007
    
    
    2006
    
    
    2005Net income (loss)
    
    $
    1,110
    
    
    $
    475
    
    
    $
    (606
    )Foreign currency translation adjustments (net of income tax
benefits of less than $1 in 2006 and $13 in 2005)
    
    
    
    
    
    
    4
    
    
    
    (9
    )Pension and postretirement obligationsUnrealized actuarial gains (losses) arising during period
(net of taxes of $91 in 2007, $3 in 2006 and $2 in 2005)
    
    
    181
    
    
    
    5
    
    
    
    (3
    )Reclassification
adjustments (net of taxes of $13 in 2007)
    
    
    26
    
    
    
    
    
    
    
    Cash flow hedging activities:Unrealized mark-to-market gains (losses) arising during
period (net of income tax of $2 in 2007, $196 in 2006
and $229 in 2005)
    
    
    (3
    )
    
    
    352
    
    
    
    (415
    )Reclassification adjustments for changes in initial
value to settlement date (net of income tax of $65 in
2007, $15 in 2006 and $46 in 2005)
    
    
    (112
    )
    
    
    22
    
    
    
    79Investments available for sale:Unrealized gains arising during period (net of income
tax of $2 in 2007, $16 in 2006 and $9 in 2005)
    
    
    3
    
    
    
    28
    
    
    
    15Realized gains reclassified from accumulated other
comprehensive income during period (net of income tax of
$8 in 2007 and $17 in 2006)
    
    
    (15
    )
    
    
    (31
    )
    
    
    Other comprehensive income (loss)
    
    
    80
    
    
    
    380
    
    
    
    (333
    )Comprehensive income (loss)
    
    $
    1,190
    
    
    $
    855
    
    
    $
    (939
    )
  91




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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
   Use of Estimates
  Regulated Operations
 Accounting for the Effects of Certain
Types of Regulation.
 Cash and Cash Equivalents
   Allowance for Doubtful Accounts
  92




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##### Table of Contents



Inventory
  Property, Plant and Equipment
 Pipelines and Other (Excluding Natural Gas and Oil Properties).
   Natural Gas and Oil Properties.
    Asset and Investment Divestitures/Impairments
  93




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##### Table of Contents



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.
 Exploration and Production revenues.
 94




---



##### Table of Contents



Marketing revenues. Price Risk
Management Activities
 Environmental Costs and Other Contingencies
 Environmental Costs.
  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
    
    derivatives not intended to hedge these exposures, including those related to our legacy
trading activities that we entered into with the objective of generating profits from
exposure to shifts or changes in market prices.
 Offsetting of Amounts Related to Certain
Contracts
   95




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##### Table of Contents



Income Taxes
  Accounting for Uncertainty
in Income Taxes. Accounting for Income Taxes,
 Foreign Currency Translation
  Accounting for Asset Retirement Obligations
 Accounting
for Asset Retirement Obligations Accounting for Conditional Asset Retirement Obligations
 Accounting for Stock-Based Compensation.
 Share-Based Payment, Accounting for Stock Issued to Employees,
 96




---



##### Table of Contents



Net loss available to common stockholders, as reported
    
    $
    (633
    )Add: Stock-based employee compensation expense included in reported net loss, net of taxes
    
    
    12Deduct: Total stock-based compensation expense determined under fair-value based method
for all awards, net of taxes
    
    
    (19
    )Net loss available to common stockholders, pro forma
    
    $
    (640
    )Loss per common share:Basic and diluted, as reported
    
    $
    (0.98
    )Basic and diluted, pro forma
    
    $
    (0.99
    )
 New Accounting Pronouncements Issued But Not Yet Adopted
  Fair Value Measurements. Fair Value
Measurements
 Measurement Date of Pension and Other Postretirement Benefits.
 Fair Value Option. Fair Value Option for
Financial Assets and Financial Liabilities Accounting for Certain Investments in Debt and Equity Securities
 Business Combinations. Business
Combinations
 Noncontrolling Interests. Noncontrolling
Interests in Consolidated Financial Statements,
 97




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##### Table of Contents



2. Acquisitions and Divestitures
 Acquisitions
 Peoples
Energy Production Company (Peoples).
 South Texas properties.
 Medicine Bow.
 Gulf LNG.
 Divestitures
  2007
    
    
    2006
    
    
    2005(In millions)Power
    
    $
    1
    
    
    $
    531
    
    
    $
    625Field Services
    
    
    
    
    
    
    
    
    
    
    657Exploration and Production
    
    
    2
    
    
    
    122
    
    
    
    7Marketing
    
    
    24
    
    
    
    
    
    
    
    Pipelines
    
    
    36
    
    
    
    3
    
    
    
    49Corporate
    
    
    3
    
    
    
    2
    
    
    
    121Total continuing(1)
    
    
    66
    
    
    
    658
    
    
    
    1,459Discontinued
    
    
    3,660
    
    
    
    368
    
    
    
    577Total
    
    $
    3,726
    
    
    $
    1,026
    
    
    $
    2,036
 
 (1)
    
    Proceeds exclude any returns of capital on our
investments in unconsolidated affiliates and cash
transferred with the assets sold and include costs
incurred in preparing assets for disposal. These items
increased our sales proceeds by $40 million for the year
ended December 31, 2007, increased our sales proceeds by
$15 million for the year ended December 31, 2006, and
decreased our sales proceeds by $35 million for the years
ended December 31, 2005. Power.
 Field Services.
 98




---



##### Table of Contents



Exploration and Production, Marketing, Pipelines and Corporate.
 Discontinued Operations and Assets Held for Sale
 Accounting for the Impairment or Disposal of Long-Lived Assets
 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 only recorded deferred taxes on individual
assets/liabilities and a portion of our investment in the stock of one of these companies;
 
    
    In 2005, (i) impairments and operating losses of certain foreign investments for
which no tax benefit was available, (ii) receipt of  dividends from foreign subsidiaries taxable
in the U.S. and (iii) state income taxes.
 99




---



##### Table of Contents



SouthLouisianaGatheringANR and
    
    
    International
    
    
    andRelated
    
    
    Power
    
    
    ProcessingOperations
    
    
    Operations
    
    
    Operations
    
    
    Other
    
    
    Total(In millions)Year Ended December 31, 2007Revenues
    
    $
    101
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    101Costs and expenses
    
    
    (43
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (43
    )Other expense(1)
    
    
    (7
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (7
    )Interest and debt expense
    
    
    (10
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (10
    )Income taxes
    
    
    (15
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (15
    )Income from operations
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    26Gain on sale, net of income taxes of $354 million
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    648Income
from discontinued operations, net of income taxes
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    674Year 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 taxes
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (274
    )Loss 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 taxes
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (179
    )Loss from discontinued operations, net of income taxes
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    (96
    )
 
 (1)
    
    Includes a loss of approximately $19 million associated with the extinguishment of certain debt obligations. ANR andRelatedOperations(In millions)December 31, 2006Assets of discontinued operationsAccounts and notes receivable
    
    $
    19Other current assets
    
    
    757Property, plant and equipment, net
    
    
    3,357Total assets
    
    $
    4,133Liabilities of discontinued operationsAccounts payable
    
    $
    64Other current liabilities
    
    
    160Long-term debt
    
    
    741Deferred income taxes
    
    
    852Total liabilities
    
    $
    1,817
 100




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##### Table of Contents



3. Other Income and Other Expenses
  2007
    
    
    2006
    
    
    2005(In millions)Other IncomeInterest income
    
    $
    49
    
    
    $
    138
    
    
    $
    125Allowance for funds used during construction
    
    
    32
    
    
    
    20
    
    
    
    23Deferred taxes on capitalized funds used during construction
    
    
    18
    
    
    
    11
    
    
    
    14Development, management and administrative services fees on power projects from affiliates
    
    
    3
    
    
    
    7
    
    
    
    11Reversal of liability for legacy crude oil purchases (see Note 12)
    
    
    77
    
    
    
    
    
    
    
    Foreign currency gain, net
    
    
    
    
    
    
    
    
    
    
    36Gain on sale of non-equity method investments
    
    
    24
    
    
    
    47
    
    
    
    40Dividend income
    
    
    
    
    
    
    14
    
    
    
    19Other
    
    
    11
    
    
    
    8
    
    
    
    17Total
    
    $
    214
    
    
    $
    245
    
    
    $
    285Other ExpensesForeign currency losses, net
    
    $
    1
    
    
    $
    20
    
    
    $
    Loss on sale of non-equity method investments
    
    
    
    
    
    
    12
    
    
    
    Other
    
    
    10
    
    
    
    8
    
    
    
    17Total
    
    $
    11
    
    
    $
    40
    
    
    $
    17
 
 4. Income Taxes
 Pretax Income (Loss) and Income Tax Expense (Benefit).
 2007
    
    
    2006
    
    
    2005(In millions)Pretax Income (Loss)U.S.
    
    $
    587
    
    
    $
    442
    
    
    $
    (872
    )Foreign
    
    
    71
    
    
    
    80
    
    
    
    35$
    658
    
    
    $
    522
    
    
    $
    (837
    )Components of Income Tax Expense (Benefit)CurrentFederal
    
    $
    (1
    )
    
    $
    7
    
    
    $
    (13
    )State
    
    
    33
    
    
    
    (15
    )
    
    
    (37
    )Foreign
    
    
    8
    
    
    
    19
    
    
    
    2240
    
    
    
    11
    
    
    
    (28
    )DeferredFederal
    
    
    217
    
    
    
    (46
    )
    
    
    (372
    )State
    
    
    (39
    )
    
    
    32
    
    
    
    67Foreign
    
    
    4
    
    
    
    (6
    )
    
    
    2182
    
    
    
    (20
    )
    
    
    (303
    )Total income taxes
    
    $
    222
    
    
    $
    (9
    )
    
    $
    (331
    )
 101




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##### Table of Contents



Effective Tax Rate Reconciliation.
 2007
    
    
    2006
    
    
    2005(In millions, except rates)Income taxes at the statutory federal rate of 35%
    
    $
    230
    
    
    $
    183
    
    
    $
    (293
    )Increase (decrease)Audit settlements
    
    
    
    
    
    
    (159
    )
    
    
    (58
    )Earnings from unconsolidated affiliates where we anticipate receiving dividends
    
    
    (40
    )
    
    
    (35
    )
    
    
    (36
    )Texas margins tax credit on accumulated net operating loss
    
    
    (16
    )
    
    
    
    
    
    
    State income taxes, net of federal income tax effect
    
    
    14
    
    
    
    20
    
    
    
    (16
    )Sales and write-offs of foreign investments
    
    
    1
    
    
    
    (17
    )
    
    
    (7
    )Foreign income taxed at different rates
    
    
    24
    
    
    
    (13
    )
    
    
    75IRS interest refund
    
    
    
    
    
    
    (11
    )
    
    
    Valuation allowances
    
    
    10
    
    
    
    23
    
    
    
    34Non-taxable Medicare reimbursements
    
    
    (3
    )
    
    
    (6
    )
    
    
    (25
    )Other
    
    
    2
    
    
    
    6
    
    
    
    (5
    )Income taxes
    
    $
    222
    
    
    $
    (9
    )
    
    $
    (331
    )Effective tax rate
    
    
    34
    %
    
    
    (2
    )%
    
    
    40
    %
  Deferred Tax Assets and Liabilities.
 2007
    
    
    2006(In millions)Deferred tax liabilitiesProperty, plant and equipment
    
    $
    3,106
    
    
    $
    2,736Investments in affiliates
    
    
    227
    
    
    
    555Regulatory and other assets
    
    
    107
    
    
    
    53Total deferred tax liability
    
    
    3,440
    
    
    
    3,344Deferred tax assetsNet operating loss and tax credit carryoversFederal
    
    
    1,135
    
    
    
    1,560State
    
    
    188
    
    
    
    214Foreign
    
    
    105
    
    
    
    81Price risk management activities
    
    
    439
    
    
    
    284Legal and other reserves
    
    
    321
    
    
    
    332Other
    
    
    464
    
    
    
    568Valuation allowance
    
    
    (137
    )
    
    
    (127
    )Total deferred tax asset
    
    
    2,515
    
    
    
    2,912Net deferred tax liability
    
    $
    925
    
    
    $
    432
  102




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##### Table of Contents



Unrecognized Tax Benefits (Liabilities) for Uncertain Tax Matters (FIN No. 48).
  Balance at January 1, 2007(1)
    
    $
    139Additions:Tax positions taken in prior years
    
    
    2Tax positions taken in current year
    
    
    23Foreign currency fluctuations
    
    
    1Reductions:Tax positions taken in prior years
    
    
    (5
    )Settlements with taxing authorities
    
    
    (3
    )Balance at December 31, 2007(2)
    
    $
    157
 
 (1)
    
    Balance at January 1, 2007 including $39 million of interest and
penalties was $178 million.(2)
    
    There were no lapses in statutes of limitations during 2007 that impacted
our unrecognized tax benefits.   Tax Credit and NOL Carryovers.
 Carryover Period2008
    
    2009-2012
    
    2013-2017
    
    2018-2027
    
    Total(In millions)U.S. federal net operating loss
    
    $
    
    
    
    $
    19
    
    
    $
    17
    
    
    $
    2,335
    
    
    $
    2,371State net operating loss
    
    
    197
    
    
    
    752
    
    
    
    553
    
    
    
    1,224
    
    
    
    2,726
  103




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##### Table of Contents



Valuation Allowances.
 
 5. Earnings Per Share
  2007
    
    
    2006
    
    
    2005Basic
    
    
    Diluted
    
    
    Basic
    
    
    Diluted
    
    
    Basic
    
    
    Diluted(In millions, except per share amounts)Income (loss) from continuing operations
    
    $
    436
    
    
    $
    436
    
    
    $
    531
    
    
    $
    531
    
    
    $
    (506
    )
    
    $
    (506
    )Convertible preferred stock dividends
    
    
    (37
    )
    
    
    (37
    )
    
    
    (37
    )
    
    
    
    
    
    
    (27
    )
    
    
    (27
    )Income (loss) from continuing operations available to
common stockholders
    
    
    399
    
    
    
    399
    
    
    
    494
    
    
    
    531
    
    
    
    (533
    )
    
    
    (533
    )Discontinued operations
    
    
    674
    
    
    
    674
    
    
    
    (56
    )
    
    
    (56
    )
    
    
    (96
    )
    
    
    (96
    )Cumulative effect of accounting changes, net of income taxes
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (4
    )
    
    
    (4
    )Net income (loss) available to common stockholders
    
    $
    1,073
    
    
    $
    1,073
    
    
    $
    438
    
    
    $
    475
    
    
    $
    (633
    )
    
    $
    (633
    )Weighted average common shares outstanding
    
    
    696
    
    
    
    696
    
    
    
    678
    
    
    
    678
    
    
    
    646
    
    
    
    646Effect of dilutive securities:Options and restricted stock
    
    
    
    
    
    
    3
    
    
    
    
    
    
    
    4
    
    
    
    
    
    
    
    Convertible preferred stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    57
    
    
    
    
    
    
    
    Weighted average common shares outstanding and dilutive
potential common shares
    
    
    696
    
    
    
    699
    
    
    
    678
    
    
    
    739
    
    
    
    646
    
    
    
    646Earnings per common share:Income (loss) from continuing operations
    
    $
    0.57
    
    
    $
    0.57
    
    
    $
    0.73
    
    
    $
    0.72
    
    
    $
    (0.82
    )
    
    $
    (0.82
    )Discontinued operations, net of income taxes
    
    
    0.97
    
    
    
    0.96
    
    
    
    (0.08
    )
    
    
    (0.08
    )
    
    
    (0.15
    )
    
    
    (0.15
    )Cumulative effect of accounting changes, net of income taxes
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (0.01
    )
    
    
    (0.01
    )Net income (loss)
    
    $
    1.54
    
    
    $
    1.53
    
    
    $
    0.65
    
    
    $
    0.64
    
    
    $
    (0.98
    )
    
    $
    (0.98
    )
  
 6. Fair Value of Financial Instruments
 As of December 31,2007
    
    2006Carrying
    
    Fair
    
    Carrying
    
    FairAmount
    
    Value
    
    Amount
    
    Value(In millions)Long-term financing obligations, including current maturities
    
    $
    12,814
    
    
    $
    13,113
    
    
    $
    14,689
    
    
    $
    15,487Commodity-based price risk management derivatives
    
    
    (892
    )
    
    
    (892
    )
    
    
    (395
    )
    
    
    (395
    )Interest rate and foreign currency derivatives
    
    
    109
    
    
    
    109
    
    
    
    43
    
    
    
    43Investments
    
    
    4
    
    
    
    4
    
    
    
    23
    
    
    
    23
 104




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##### Table of Contents



7. Price Risk Management Activities
  As of December 31,2007
    
    
    2006(In millions)Net assets (liabilities)Derivatives designated as hedges
    
    $
    (23
    )
    
    $
    61Other commodity-based derivative contracts
    
    
    (869
    )
    
    
    (456
    )Total commodity-based derivatives
    
    
    (892
    )
    
    
    (395
    )Interest rate and foreign currency derivatives
    
    
    109
    
    
    
    43Net liabilities from price risk management activities(1)
    
    $
    (783
    )
    
    $
    (352
    )
 
 (1)
    
    Included in both current and non-current assets and liabilities on the balance sheet.  Derivatives Designated as Hedges
  105




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##### Table of Contents



Cash Flow Hedges.
 AccumulatedOther
    
    
    EstimatedComprehensive
    
    
    Income (Loss)
    
    
    FinalIncome (Loss)
    
    
    Reclassification
    
    
    Termination2007
    
    
    2006
    
    
    in 2008(1)
    
    
    Year(In millions)Commodity cash flow hedgesHeld by consolidated entities
    
    $
    (25
    )
    
    $
    84
    
    
    $
    46
    
    
    
    2012Held by unconsolidated affiliates
    
    
    (4
    )
    
    
    (4
    )
    
    
    (1
    )
    
    
    2013Total commodity cash flow hedges
    
    
    (29
    )
    
    
    80
    
    
    
    45Interest rate and foreign currency cash flow hedgesFixed rate
    
    
    (2
    )
    
    
    3
    
    
    
    
    
    
    
    2015De-designated
    
    
    (4
    )
    
    
    (3
    )
    
    
    
    
    
    
    2009Total foreign currency cash flow hedges
    
    
    (6
    )
    
    
    
    
    
    
    Total interest rate and cash flow hedges
    
    $
    (35
    )
    
    $
    80
    
    
    $
    45
 
 (1)
    
    Reclassifications occur upon the physical delivery of the hedged commodity or if the forecasted transaction is no longer probable.  Fair Value Hedges.
 Hedged
    
    
    Price Risk ManagementWeighted
    
    
    Debt
    
    
    Asset (Liability)(1)Derivative
    
    Average Rate
    
    
    2007
    
    
    2006
    
    
    2007
    
    
    2006Fixed-to-floating swaps
    
    LIBOR + 4.18%
    
    $
    218
    
    
    $
    440
    
    
    $
    (5
    )
    
    $
    (31
    )Fixed-to-floating cross
currency swaps(2)
    
    LIBOR + 4.23%
    
    
    379
    
    
    
    402
    
    
    
    118
    
    
    
    67$
    113
    
    
    $
    36
 
 (1)
    
    We did not record any ineffectiveness related to our fair value hedges in 2006 or 2007.(2)
    
    As of December 31, 2007 and 2006, these derivatives, when combined with our Euro denominated
debt, converted 330 million Euro and 350 million Euro of our debt to $379 million and $402
million. Other Commodity-Based Derivatives.
  Credit Risk
  106




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##### Table of Contents



Below
    
    
    NotCounterparty
    
    Investment Grade(1)
    
    
    Investment Grade(1)
    
    
    Rated(1)
    
    
    Total(In millions)December 31, 2007Energy marketers
    
    $
    30
    
    
    $
    110
    
    
    $
    
    
    
    $
    140Natural gas and electric utilities
    
    
    
    
    
    
    
    
    
    
    71
    
    
    
    71Financial institutions and other
    
    
    86
    
    
    
    
    
    
    
    
    
    
    
    86Net financial instrument assets
    
    
    116
    
    
    
    110
    
    
    
    71
    
    
    
    297Collateral held by us
    
    
    
    
    
    
    (100
    )
    
    
    (47
    )
    
    
    (147
    )Net exposure from derivative assets
    
    $
    116
    
    
    $
    10
    
    
    $
    24
    
    
    $
    150
 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
    
    
    616
    
    
    
    81
    
    
    
    65
    
    
    
    762Collateral held by us
    
    
    (328
    )
    
    
    (78
    )
    
    
    (64
    )
    
    
    (470
    )Net exposure from derivative assets
    
    $
    288
    
    
    $
    3
    
    
    $
    1
    
    
    $
    292
 
 (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.   107




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##### Table of Contents



8. Regulatory Assets and Liabilities
  2007
    
    
    2006(In millions)Current regulatory assets
    
    $
    
    
    
    $
    6Non-current regulatory assetsTaxes on capitalized funds used during construction
    
    
    122
    
    
    
    106Postretirement benefits
    
    
    18
    
    
    
    22Unamortized net loss on reacquired debt
    
    
    59
    
    
    
    19Under-collected income taxes
    
    
    8
    
    
    
    3Other
    
    
    14
    
    
    
    21Total non-current regulatory assets
    
    
    221
    
    
    
    171Total regulatory assets
    
    $
    221
    
    
    $
    177Current regulatory liabilities
    
    $
    41
    
    
    $
    16Non-current regulatory liabilitiesEnvironmental liability
    
    
    143
    
    
    
    130Cost of removal of offshore assets
    
    
    7
    
    
    
    12Property and plant depreciation
    
    
    67
    
    
    
    70Postretirement benefits
    
    
    90
    
    
    
    19Plant regulatory liability
    
    
    11
    
    
    
    11Excess deferred income taxes
    
    
    3
    
    
    
    6Other
    
    
    7
    
    
    
    4Total non-current regulatory liabilities
    
    
    328
    
    
    
    252Total regulatory liabilities
    
    $
    369
    
    
    $
    268
 
 9. Other Assets and Liabilities
  2007
    
    
    2006(In millions)Other current assetsPrepaid expenses
    
    $
    66
    
    
    $
    72Margin and other deposits held by others
    
    
    27
    
    
    
    60Deposits
    
    
    
    
    
    
    60Other
    
    
    34
    
    
    
    45Total
    
    $
    127
    
    
    $
    237Other non-current assetsPension, other postretirement and postemployment benefits (Note 13)
    
    $
    660
    
    
    $
    332Notes receivable from affiliates
    
    
    220
    
    
    
    232Restricted cash (Note 1)
    
    
    91
    
    
    
    123Unamortized debt expenses
    
    
    107
    
    
    
    133Regulatory assets (Note 8)
    
    
    221
    
    
    
    171Long-term receivables
    
    
    116
    
    
    
    131Other
    
    
    182
    
    
    
    173Total
    
    $
    1,597
    
    
    $
    1,295
 108




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##### Table of Contents



2007
    
    
    2006(In millions)Other current liabilitiesAccrued taxes, other than income
    
    $
    89
    
    
    $
    95Income taxes
    
    
    47
    
    
    
    17Environmental, legal and rate reserves (Note 12)
    
    
    174
    
    
    
    560Deposits
    
    
    62
    
    
    
    30Pension and other postretirement benefits (Note 13)
    
    
    28
    
    
    
    30Accrued lease obligations
    
    
    
    
    
    
    56Asset retirement obligations (Note 10)
    
    
    41
    
    
    
    89Dividends payable
    
    
    37
    
    
    
    37Regulatory liabilities (Note 8)
    
    
    41
    
    
    
    16Other
    
    
    114
    
    
    
    103Total
    
    $
    633
    
    
    $
    1,033Other non-current liabilitiesEnvironmental and legal reserves (Note 12)
    
    $
    590
    
    
    $
    616Pension, other postretirement and postemployment benefits (Note 13)
    
    
    236
    
    
    
    294Regulatory liabilities (Note 8)
    
    
    328
    
    
    
    252Asset retirement obligations (Note 10)
    
    
    212
    
    
    
    154Other deferred credits
    
    
    62
    
    
    
    159Insurance reserves
    
    
    111
    
    
    
    118Other
    
    
    211
    
    
    
    97Total
    
    $
    1,750
    
    
    $
    1,690
 
 10. 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
    
    
    
    15-26Gathering and processing systems
    
    Straight-line
    
    
    
    15-40Transportation equipment
    
    Straight-line
    
    
    
    5Buildings and improvements
    
    Straight-line
    
    
    
    4-49Office and miscellaneous equipment
    
    Straight-line
    
    
    
    1-10
 
 (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 costs.
 Capitalized costs during construction.
 109




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##### Table of Contents



Construction
work-in progress.
 Asset retirement obligations.
   2007
    
    
    2006(In millions)Net asset retirement liability at January 1
    
    $
    243
    
    
    $
    252Liabilities settled
    
    
    (62
    )
    
    
    (48
    )Accretion expense
    
    
    23
    
    
    
    19Liabilities incurred
    
    
    16
    
    
    
    5Changes in estimate
    
    
    33
    
    
    
    15Net asset retirement liability at December 31
    
    $
    253
    
    
    $
    243
 
 11. Debt, Other Financing Obligations and Other Credit Facilities
 Year Ended December 31,2007
    
    
    2006(In millions)Short-term financing obligations, including current maturities
    
    $
    331
    
    
    $
    1,360Long-term financing obligations
    
    
    12,483
    
    
    
    13,329Total
    
    $
    12,814
    
    
    $
    14,689
 110




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##### Table of Contents



Colorado Interstate Gas Company (CIG)Notes, 5.95% through 6.85%, due 2015 through 2037
    
    $
    575
    
    
    $
    700El Paso CorporationNotes, 6.375% through 10.75%, due 2008 through 2037
    
    
    6,090
    
    
    
    7,939$1.25 billion
revolver, variable due 2009
    
    
    
    
    
    
    200$1.5 billion revolver, variable due 2012
    
    
    425
    
    
    
    El Paso Natural Gas Company (EPNG)Notes, 5.95% through 8.625%, due 2010 through 2032
    
    
    1,169
    
    
    
    1,115El Paso Exploration & Production Company (EPEP)Senior note, 7.75%, due 2013
    
    
    1
    
    
    
    1,200Revolving credit facility, variable due 2012
    
    
    750
    
    
    
    Revolving credit facility, variable due 2010
    
    
    
    
    
    
    145El Paso Pipeline Partners, L.P.Revolving credit facility, variable due 2012
    
    
    455
    
    
    
    Southern Natural Gas Company (SNG)Notes, 5.9% through 8.0%, due 2008 through 2032
    
    
    1,134
    
    
    
    1,200Tennessee Gas Pipeline CompanyNotes, 6.0% through 8.375%, due 2011 through 2037
    
    
    1,626
    
    
    
    1,626Other
    
    
    297
    
    
    
    31012,522
    
    
    
    14,435Other financing obligationsCapital Trust I, due 2028
    
    
    325
    
    
    
    325Subtotal
    
    
    12,847
    
    
    
    14,760Less:Other, including unamortized discounts and premiums
    
    
    33
    
    
    
    71Current maturities
    
    
    331
    
    
    
    1,360Total long-term financing obligations, less current maturities
    
    $
    12,483
    
    
    $
    13,329
 Changes in Long-Term Financing Obligations.
 CashBook Value
    
    
    Received /Company
    
    Interest Rate
    
    Increase (Decrease)
    
    
    (Paid)IssuancesEPEPRevolving credit facility due 2012
    
    variable
    
    $
    955
    
    
    $
    952El PasoRevolving credit facility due 2012
    
    variable
    
    
    3,125
    
    
    
    3,117Notes due 2014
    
    6.875%
    
    
    374
    
    
    
    371Notes due 2017
    
    7.00%
    
    
    893
    
    
    
    886EPNG notes due 2017
    
    5.95%
    
    
    354
    
    
    
    350El Paso Pipeline Partners, L.P.Revolving
credit facility due 2012
    
    variable
    
    
    455
    
    
    
    454SNG notes due 2017
    
    5.90%
    
    
    500
    
    
    
    494Increases through December 31, 2007
    
    
    
    $
    6,656
    
    
    $
    6,624Repayments, repurchases and otherEl Paso
    
    6.375%-10.75%
    
    $
    (3,001
    )
    
    $
    (3,175
    )El Paso-Euro
    
    7.125%
    
    
    (157
    )
    
    
    (165
    )EPEP
    
    7.75%
    
    
    (1,199
    )
    
    
    (1,267
    )SNG
    
    6.70%
    
    
    (100
    )
    
    
    (100
    )SNG
    
    8.875%
    
    
    (398
    )
    
    
    (418
    )SNG
    
    6.125%
    
    
    (66
    )
    
    
    (66
    )CIG
    
    5.95%
    
    
    (125
    )
    
    
    (127
    )EPNG
    
    7.625%
    
    
    (299
    )
    
    
    (314
    )Other
    
    various
    
    
    64
    
    
    
    (20
    )(5,281
    )
    
    
    (5,652
    )
 111




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##### Table of Contents



CashBook Value
    
    
    Received /Interest Rate
    
    
    Increase (Decrease)
    
    
    (Paid)Revolving Credit FacilitiesEPEP
    
    variable
    
    
    (350
    )
    
    
    (350
    )El Paso
    
    variable
    
    
    (2,900
    )
    
    
    (2,900
    )Decreases through December 31, 2007
    
    
    
    
    
    $
    (8,531
    )
    
    $
    (8,902
    )
   Debt Maturities.
 2008
    
    $
    3312009
    
    
    1,0952010
    
    
    2512011
    
    
    6432012
    
    
    2,075Thereafter
    
    
    8,452Total long-term financing obligations, including current maturities
    
    $
    12,847
 Credit Facilities/Letters of Credit
  $1.5 Billion Revolving Credit Agreement.
  Unsecured Revolving Credit Facility.
 Unsecured Credit Facility. .
 112




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##### Table of Contents



EPEP $1.0 Billion Revolving Credit Agreement.
 Contingent Letter of Credit Facility.
 El Paso Pipeline
Partners, L.P. Revolving Credit Facility.
 Letters of Credit.
 Restrictive Covenants
 $1.5 billion Revolving Credit Agreement.
 (a)
    
    Our ratio of Debt to Consolidated EBITDA, each as defined in the credit agreement, shall
not exceed 5.5 to 1 at anytime prior to June 30, 2008. Thereafter it shall not exceed 5.25
to 1 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 June 30, 2008.
Thereafter it shall not be less than 2.00 to 1 until maturity;(c)
    
    EPNG and TGP 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 $1.0 Billion Revolving Credit Agreement.
 113




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##### Table of Contents



EPPP Revolving Credit Facility.
 Other Restrictions and Provisions.
  Other Financing Arrangements
 Capital Trusts.
  Non-Recourse Project Financings.
 114




---



##### Table of Contents



12. Commitments and Contingencies
 Legal Proceedings
 ERISA Class Action Suit. William
H. Lewis, III v. El Paso Corporation, et al.
 Cash Balance Plan Lawsuit. Tomlinson, et al. v. El Paso Corporation and El Paso Corporation Pension Plan
 Shareholder
Litigation.
 Retiree Medical Benefits Matters. Yolton et
al. v. El Paso Tennessee Pipeline Co. and Case Corporation.
 Natural Gas Commodities Litigation.
 115




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##### Table of Contents



Gas Measurement Cases. In re: Natural Gas Royalties
Qui Tam Litigation,
 Will Price, et al. v.
Gas Pipelines and Their Predecessors, et al.,
 MTBE
 Government Investigations and Inquiries
 Reserve Revisions.
 Legacy
Crude Oil Trading.
 116




---



##### Table of Contents



Rates and Regulatory Matters
 Notice of Inquiry on Pipeline Fuel Retention Policies
 Notice
of Proposed Rulemaking.
 EPNG.
 Other Contingencies
 Navajo Nation
 117




---



##### Table of Contents



Environmental Matters
   December 31, 2007Sites
    
    Expected
    
    
    High(In millions)Operating
    
    $
    22
    
    
    $
    28Non-operating
    
    
    211
    
    
    
    393Superfund
    
    
    27
    
    
    
    49Total
    
    $
    260
    
    
    $
    470
  Balance as of January 1, 2007
    
    $
    314Additions/adjustments for remediation activities
    
    
    21Payments for remediation activities
    
    
    (75
    )Balance as of December 31, 2007
    
    $
    260
  CERCLA Matters.
  118




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##### Table of Contents



Commitments, Purchase Obligations and Other Matters
 Operating Leases.
 Year Ending December 31,
    
    OperatingLeases(1)(In millions)2008
    
    $
    142009
    
    
    132010
    
    
    102011
    
    
    72012
    
    
    7Thereafter
    
    
    29Total
    
    $
    80
 
 (1)
    
    Amounts have not been reduced by minimum sublease rentals of approximately $1 million due
in the future under noncancelable subleases.  Guarantees.
  Retiree Medical Benefits Matters
 Other Commercial Commitments.
 Navajo Nation
 119




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##### Table of Contents



13. Retirement Benefits
 Overview of Retirement Benefits
 Pension Benefits.
  Retirement Savings Plan.
 Other Postretirement Benefits.
 Pension and Other Postretirement Benefits. Employers Accounting for
Postretirement Benefits Other Than Pensions,
  OtherPension Benefits
    
    Postretirement Benefits2007
    
    2006
    
    2007
    
    2006(In millions)Projected benefit obligation/accumulated postretirement benefit obligation
    
    $
    2,027
    
    
    $
    2,157
    
    
    $
    418
    
    
    $
    494Fair value of plan assets
    
    
    2,537
    
    
    
    2,382
    
    
    
    303
    
    
    
    276Current benefit liability
    
    
    4
    
    
    
    5
    
    
    
    24
    
    
    
    25Non-current benefit liability
    
    
    33
    
    
    
    52
    
    
    
    192
    
    
    
    228Non-current benefit asset
    
    
    550
    
    
    
    285
    
    
    
    106
    
    
    
    44Accumulated other comprehensive income (loss), net of income taxes
    
    $
    (269
    )
    
    $
    (450
    )
    
    $
    32
    
    
    $
    15
 120




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##### Table of Contents



Change in Benefit Obligation, Plan Assets and Funded Status.
 OtherPostretirementPension Benefits
    
    
    Benefits2007
    
    
    2006
    
    
    2007
    
    
    2006(In millions)Change in benefit obligation(1):Benefit obligation  beginning of period
    
    $
    2,157
    
    
    $
    2,235
    
    
    $
    494
    
    
    $
    527Service cost
    
    
    17
    
    
    
    17
    
    
    
    1
    
    
    
    11Interest cost
    
    
    119
    
    
    
    118
    
    
    
    26
    
    
    
    26Participant contributions
    
    
    
    
    
    
    
    
    
    
    32
    
    
    
    34Actuarial gain
    
    
    (86
    )
    
    
    (37
    )
    
    
    (66
    )
    
    
    (35
    )Benefits paid
    
    
    (186
    )
    
    
    (176
    )
    
    
    (69
    )
    
    
    (69
    )Other
    
    
    6
    
    
    
    
    
    
    
    
    
    
    
    Benefit obligation  end of period
    
    $
    2,027
    
    
    $
    2,157
    
    
    $
    418
    
    
    $
    494Change in plan assets:Fair value of plan assets at beginning of period
    
    $
    2,382
    
    
    $
    2,350
    
    
    $
    276
    
    
    $
    251Actual return on plan assets(2)
    
    
    333
    
    
    
    192
    
    
    
    39
    
    
    
    19Employer contributions
    
    
    8
    
    
    
    16
    
    
    
    25
    
    
    
    41Participant contributions
    
    
    
    
    
    
    
    
    
    
    32
    
    
    
    34Benefits paid
    
    
    (186
    )
    
    
    (176
    )
    
    
    (69
    )
    
    
    (69
    )Fair value of plan assets at end of period
    
    $
    2,537
    
    
    $
    2,382
    
    
    $
    303
    
    
    $
    276Reconciliation of funded status:Fair value of plan assets at September 30
    
    $
    2,537
    
    
    $
    2,382
    
    
    $
    303
    
    
    $
    276Less: Benefit obligation  end of period
    
    
    2,027
    
    
    
    2,157
    
    
    
    418
    
    
    
    494Funded status at September 30
    
    
    510
    
    
    
    225
    
    
    
    (115
    )
    
    
    (218
    )Fourth quarter contributions and income
    
    
    3
    
    
    
    3
    
    
    
    5
    
    
    
    9Net asset (liability) at December 31
    
    $
    513
    
    
    $
    228
    
    
    $
    (110
    )
    
    $
    (209
    )
 
 (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)
    
    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 amortized only to
the extent that our remaining unrecognized actual gains and losses exceed the greater of 10 percent of our projected
benefit obligations or market related value of plan assets. Expected Payment of Future Benefits.
 Year Ending
    
    
    
    
    
    Other PostretirementDecember 31
    
    Pension Benefits
    
    Benefits(1)(In millions)2008
    
    $
    167
    
    
    $
    442009
    
    
    167
    
    
    
    432010
    
    
    166
    
    
    
    422011
    
    
    164
    
    
    
    412012
    
    
    163
    
    
    
    392013-2017
    
    
    793
    
    
    
    173
 
 (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. 121




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##### Table of Contents



Components of Net Benefit Cost (Income).
 Pension Benefits
    
    
    Other Postretirement Benefits2007
    
    
    2006
    
    
    2005
    
    
    2007
    
    
    2006
    
    
    2005(In millions)Service cost
    
    $
    17
    
    
    $
    17
    
    
    $
    22
    
    
    $
    1
    
    
    $
    11
    
    
    $
    1Interest cost
    
    
    119
    
    
    
    118
    
    
    
    121
    
    
    
    26
    
    
    
    26
    
    
    
    29Expected return on plan assets
    
    
    (181
    )
    
    
    (175
    )
    
    
    (168
    )
    
    
    (16
    )
    
    
    (14
    )
    
    
    (12
    )Amortization of net actuarial loss
    
    
    43
    
    
    
    55
    
    
    
    69
    
    
    
    (1
    )
    
    
    
    
    
    
    Amortization of prior service cost(1)
    
    
    (2
    )
    
    
    (2
    )
    
    
    (2
    )
    
    
    (1
    )
    
    
    (1
    )
    
    
    (1
    )Other
    
    
    
    
    
    
    (2
    )
    
    
    1
    
    
    
    
    
    
    
    (1
    )
    
    
    8Net benefit cost (income)
    
    $
    (4
    )
    
    $
    11
    
    
    $
    43
    
    
    $
    9
    
    
    $
    21
    
    
    $
    25
 
 (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. Actuarial Assumptions and Sensitivity Analysis.
 OtherPension Benefits
    
    Postretirement Benefits2007
    
    2006
    
    2005
    
    2007
    
    2006
    
    2005(Percent)
    
    (Percent)Assumptions related to benefit obligations at September 30:Discount rate
    
    
    6.25
    
    
    
    5.75
    
    
    
    
    
    
    
    6.05
    
    
    
    5.50Rate of compensation increase
    
    
    4.27
    
    
    
    4.00Assumptions related to benefit costs for the year ended December 31:Discount rate
    
    
    5.75
    
    
    
    5.50
    
    
    
    5.75
    
    
    
    5.50
    
    
    
    5.25
    
    
    
    5.75Expected return on plan assets(1)
    
    
    8.00
    
    
    
    8.00
    
    
    
    8.00
    
    
    
    8.00
    
    
    
    8.00
    
    
    
    7.50Rate of compensation increase
    
    
    4.00
    
    
    
    4.00
    
    
    
    4.00
 
 (1)
    
    The expected return on plan assets is a pre-tax rate
of return based on our targeted portfolio of investments.
Some of our postretirement benefit plans investment
earnings are subject to unrelated business income tax at a
rate of 35%. The expected return on plan assets for our
postretirement benefit plans is calculated using the
after-tax rate of return.  2007
    
    2006(In millions)One percentage point increase:Aggregate of service cost and interest cost
    
    $
    1
    
    
    $
    1Accumulated postretirement benefit obligation
    
    
    13
    
    
    
    18One percentage point decrease:Aggregate of service cost and interest cost
    
    $
    (1
    )
    
    $
    (1
    )Accumulated postretirement benefit obligation
    
    
    (12
    )
    
    
    (15
    )
 122




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##### Table of Contents



Plan Assets.
 Pension Plans
    
    Other Postretirement PlansAsset Category
    
    Target
    
    Actual 2007
    
    Actual 2006
    
    Target
    
    Actual 2007
    
    Actual 2006(Percent)
    
    
    
    
    
    
    
    
    
    (Percent)Equity securities
    
    
    60
    
    
    
    67
    
    
    
    66
    
    
    
    65
    
    
    
    63
    
    
    
    63Debt securities
    
    
    40
    
    
    
    32
    
    
    
    33
    
    
    
    35
    
    
    
    33
    
    
    
    33Other
    
    
    
    
    
    
    1
    
    
    
    1
    
    
    
    
    
    
    
    4
    
    
    
    4Total
    
    
    100
    
    
    
    100
    
    
    
    100
    
    
    
    100
    
    
    
    100
    
    
    
    100
 Other Matters.
 
 14. Stockholders Equity and Minority Interest
 Stockholders Equity
 Common Stock.
 Convertible Perpetual Preferred Stock.
  Dividends.
 ConvertibleCommon Stock
    
    Preferred Stock($0.16/share)
    
    (4.99%/year)Amount paid in 2007
    
    $
    112
    
    
    $
    37Amount paid in January 2008
    
    $
    28
    
    
    $
    9Declared in 2008:Date of declaration
    
    February 7, 2008
    
    February 7, 2008Payable to shareholders on record
    
    March 7, 2008
    
    March 15, 2008Date payable
    
    April 1, 2008
    
    April 1, 2008
  123




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##### Table of Contents



Accumulated Other Comprehensive Income.
 2007
    
    
    2006Cash flow hedges (see Note 7)
    
    $
    (35
    )
    
    $
    80Pension and other postretirement benefits (see Note 13)
    
    
    (237
    )
    
    
    (435
    )Investments available for sale
    
    
    
    
    
    
    12Total accumulated other comprehensive loss, net of income taxes
    
    $
    (272
    )
    
    $
    (343
    )
 Minority Interest
  
 15. Stock-Based Compensation
 Overview.
  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, 2006
    
    
    24,135,442
    
    
    $
    35.52Granted
    
    
    4,931,457
    
    
    $
    14.77Exercised
    
    
    (768,867
    )
    
    $
    8.85Forfeited or canceled
    
    
    (1,347,888
    )
    
    $
    12.52Expired
    
    
    (2,966,149
    )
    
    $
    47.32Outstanding at December 31, 2007
    
    
    23,983,995
    
    
    $
    31.93
    
    
    
    5.03
    
    
    $
    72Vested at December 31, 2007 or expected to vest in the future
    
    
    23,590,686
    
    
    $
    32.25
    
    
    
    4.97
    
    
    $
    70Exercisable at December 31, 2007
    
    
    16,117,816
    
    
    $
    41.23
    
    
    
    3.36
    
    
    $
    37
 124




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##### Table of Contents



Fair Value Assumptions.
  2007
    
    2006
    
    2005Expected Term in Years
    
    
    6.0
    
    
    
    6.0
    
    
    
    4.8Expected Volatility
    
    
    34
    %
    
    
    38
    %
    
    
    42
    %Expected Dividends
    
    
    1
    %
    
    
    1.3
    %
    
    
    1.5
    %Risk-Free Interest Rate
    
    
    4.6
    %
    
    
    4.9
    %
    
    
    3.7
    %
 Share Based Payment
 Restricted Stock.
 Weighted AverageGrant Date Fair ValueNonvested Shares
    
    # Shares
    
    per ShareNonvested at December 31, 2006
    
    
    3,739,220
    
    
    $
    11.44Granted
    
    
    2,541,836
    
    
    $
    14.73Vested
    
    
    (1,765,800
    )
    
    $
    10.43Forfeited
    
    
    (599,316
    )
    
    $
    13.38Nonvested at December 31, 2007
    
    
    3,915,940
    
    
    $
    13.74
   125




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##### Table of Contents



Employee Stock Purchase Plan.
 
 16. Business Segment Information
  Pipelines.
 Exploration and Production.
 Marketing.
 Power.
    2007
    
    
    2006
    
    
    2005(In millions)Segment EBIT
    
    $
    1,935
    
    
    $
    1,838
    
    
    $
    979Corporate and other
    
    
    (283
    )
    
    
    (88
    )
    
    
    (521
    )Interest and debt expense
    
    
    (994
    )
    
    
    (1,228
    )
    
    
    (1,295
    )Income taxes
    
    
    (222
    )
    
    
    9
    
    
    
    331Income (loss) from continuing operations
    
    $
    436
    
    
    $
    531
    
    
    $
    (506
    )
 126




---



##### Table of Contents



As of or for the Year Ended December 31, 2007SegmentExploration and
    
    
    
    
    
    
    
    
    
    CorporatePipelines
    
    Production
    
    Marketing
    
    Power
    
    and Other(1)
    
    Total(In millions)Revenue from external customersDomestic
    
    $
    2,429
    
    
    $
    1,123
    (2)
    
    $
    814
    
    
    $
    
    
    
    $
    54
    
    
    $
    4,420Foreign
    
    
    11
    
    
    
    17
    (2)
    
    
    163
    
    
    
    
    
    
    
    37
    
    
    
    228Intersegment revenue
    
    
    54
    
    
    
    1,160
    (2)
    
    
    (1,196
    )
    
    
    
    
    
    
    (18
    )
    
    
    Operation and maintenance
    
    
    753
    
    
    
    439
    
    
    
    11
    
    
    
    17
    
    
    
    113
    
    
    
    1,333Depreciation, depletion and amortization
    
    
    373
    
    
    
    780
    
    
    
    3
    
    
    
    1
    
    
    
    19
    
    
    
    1,176Earnings (losses) from unconsolidated affiliates
    
    
    105
    
    
    
    11
    
    
    
    
    
    
    
    (15
    )
    
    
    
    
    
    
    101EBIT
    
    
    1,265
    
    
    
    909
    
    
    
    (202
    )
    
    
    (37
    )
    
    
    (283
    )(5)
    
    
    1,652Discontinued operations, net of income taxes
    
    
    674
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    674Assets of continuing operationsDomestic
    
    
    13,764
    
    
    
    7,404
    
    
    
    506
    
    
    
    5
    
    
    
    1,482
    
    
    
    23,161Foreign(3)
    
    
    175
    
    
    
    625
    
    
    
    31
    
    
    
    526
    
    
    
    61
    
    
    
    1,418Capital expenditures and investments in and
advances to unconsolidated affiliates,
net(4)
    
    
    1,059
    
    
    
    2,613
    
    
    
    
    
    
    
    (34
    )
    
    
    7
    
    
    
    3,645Total investments in unconsolidated affiliates
    
    
    759
    
    
    
    704
    
    
    
    
    
    
    
    151
    
    
    
    
    
    
    
    1,614
 
 (1)
    
    Includes eliminations of intercompany transactions. Our intersegment revenues, along with our intersegment operating expenses, were incurred in the normal course of business between our operating
segments. We recorded an intersegment revenue elimination of $19 million and an operation and maintenance expense elimination of $1 million, which is included in the Corporate column, to remove
intersegment transactions.(2)
    
    Revenues from external customers include gains and losses related to our hedging of price risk associated with our natural gas and oil production. Intersegment revenues represent sales to our
Marketing segment, which is responsible for marketing our production to third parties.(3)
    
    Of total foreign assets, approximately $0.6 billion relates to property, plant and equipment, and approximately $0.6 billion relates to investments in and advances to unconsolidated affiliates.(4)
    
    Amounts are net of third party reimbursements of our capital expenditures and returns of invested capital.(5)
    
    Includes debt extinguishment costs of $86 million related to refinancing EPEPs $1.2 billion notes. 127




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##### Table of Contents



As of or for the Year Ended December 31, 2006SegmentsExploration and
    
    
    
    
    
    
    
    
    
    Corporate(1)Pipelines
    
    Production
    
    Marketing
    
    Power
    
    and Other
    
    Total(In millions)Revenue from external customersDomestic
    
    $
    2,331
    
    
    $
    645
    (2)
    
    $
    1,012
    
    
    $
    4
    
    
    $
    116
    
    
    $
    4,108Foreign
    
    
    10
    
    
    
    32
    (2)
    
    
    131
    
    
    
    
    
    
    
    
    
    
    
    173Intersegment revenue
    
    
    61
    
    
    
    1,177
    (2)
    
    
    (1,201
    )
    
    
    2
    
    
    
    (39
    )
    
    
    Operation and maintenance
    
    
    743
    
    
    
    410
    
    
    
    28
    
    
    
    57
    
    
    
    99
    
    
    
    1,337Depreciation, depletion and amortization
    
    
    370
    
    
    
    645
    
    
    
    4
    
    
    
    2
    
    
    
    26
    
    
    
    1,047Earnings 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
    
    
    12,958
    
    
    
    5,858
    
    
    
    1,115
    
    
    
    
    
    
    
    1,950
    
    
    
    21,881Foreign(4)
    
    
    147
    
    
    
    404
    
    
    
    28
    
    
    
    618
    
    
    
    50
    
    
    
    1,247Capital 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 to third parties.(3)
    
    Excludes assets of discontinued operations of $4,133 million (see Note 2).(4)
    
    Approximately $0.4 billion of total foreign assets 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. 128




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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
    
    
    772
    
    
    
    383
    
    
    
    54
    
    
    
    122
    
    
    
    37
    
    
    
    567
    
    
    
    1,935Depreciation, depletion and
amortization
    
    
    343
    
    
    
    612
    
    
    
    4
    
    
    
    2
    
    
    
    3
    
    
    
    42
    
    
    
    1,006Earnings (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
    
    
    12,264
    
    
    
    5,215
    
    
    
    3,786
    
    
    
    70
    
    
    
    99
    
    
    
    4,081
    
    
    
    25,515Foreign(5)
    
    
    125
    
    
    
    355
    
    
    
    33
    
    
    
    1,106
    
    
    
    
    
    
    
    57
    
    
    
    1,676Capital 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 to third parties.(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 $0.3 billion 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. 129




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17. Investments in, Earnings from and Transactions with Unconsolidated Affiliates
   Net Ownership
    
    
    
    
    
    
    
    
    
    
    Earnings (Losses) fromInterest
    
    
    Investment
    
    
    Unconsolidated Affiliates2007
    
    
    2006
    
    
    2007
    
    
    2006
    
    
    2007
    
    
    2006
    
    
    2005(Percent)
    
    
    (In millions)
    
    
    
    
    
    
    (In millions)Domestic:Four Star(1)
    
    
    49
    
    
    
    43
    
    
    $
    698
    
    
    $
    723
    
    
    $
    12
    
    
    $
    10
    
    
    $
    19Citrus
    
    
    50
    
    
    
    50
    
    
    
    576
    
    
    
    597
    
    
    
    81
    
    
    
    62
    
    
    
    66Enterprise Products Partners(2)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    183Midland Cogeneration Venture(2)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    13
    
    
    
    (162
    )Javelina(2)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    121Other Domestic Investments
    
    various
    
    various
    
    
    38
    
    
    
    36
    
    
    
    3
    
    
    
    3
    
    
    
    17Total domestic
    
    
    
    
    
    
    
    
    
    
    1,312
    
    
    
    1,356
    
    
    
    96
    
    
    
    88
    
    
    
    244Foreign:Bolivia to Brazil Pipeline
    
    
    8
    
    
    
    8
    
    
    
    105
    
    
    
    105
    
    
    
    11
    
    
    
    11
    
    
    
    20Gasoductos de Chihuahua
    
    
    50
    
    
    
    50
    
    
    
    146
    
    
    
    126
    
    
    
    21
    
    
    
    25
    
    
    
    19Habibullah Power(3)
    
    
    50
    
    
    
    50
    
    
    
    17
    
    
    
    17
    
    
    
    
    
    
    
    1
    
    
    
    (13
    )Manaus/Rio Negro(4)
    
    
    100
    
    
    
    100
    
    
    
    56
    
    
    
    96
    
    
    
    (6
    )
    
    
    17
    
    
    
    19Porto Velho(3)
    
    
    50
    
    
    
    50
    
    
    
    (60
    )
    
    
    (34
    )
    
    
    (23
    )
    
    
    2
    
    
    
    (16
    )Korea Independent Energy Corporation(2)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    127EGE Itabo(2)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1
    
    
    
    (58
    )Other Foreign Investments
    
    various
    
    various
    
    
    38
    
    
    
    41
    
    
    
    2
    
    
    
    
    
    
    
    (61
    )Total foreign
    
    
    
    
    
    
    
    
    
    
    302
    
    
    
    351
    
    
    
    5
    
    
    
    57
    
    
    
    37Total investments in unconsolidated affiliates
    
    
    
    
    
    
    
    
    
    $
    1,614
    
    
    $
    1,707Total earnings from unconsolidated affiliates
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    101
    
    
    $
    145
    
    
    $
    281
 
 (1)
    
    Amortization of our purchase cost in excess of the underlying net assets of Four Star was $53 million, $54 million and $20 million during 2007, 2006 and 2005.
During the third quarter of 2007, we paid $27 million to
increase our ownership interest in Four Star from 43 percent to 49 percent.(2)
    
    We sold our interests in these investments.(3)
    
    As of December 31, 2007 and 2006, we had outstanding advances and receivables not included in these balances of $350 million and $413 million related to our foreign
investments of which $12 million and $25 million related to our investment in Habibullah Power, $335 million and $350 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 $1 million, $46 million, and
$47 million in 2007, 2006 and 2005. For a further discussion of these receivables, see Matters that Could Impact Our Investmentsbelow.(4)
    
    We transferred ownership of these plants to the power purchaser in January 2008. For a further discussion, see Matters that Could Impact Our Investmentsbelow. 130




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Investment or Group
    
    2007
    
    
    2006
    
    
    2005(In millions)Midland Cogeneration Venture(1)
    
    $
    
    
    
    $
    13
    
    
    $
    (162
    )Asia power investments
    
    
    (1
    )
    
    
    (8
    )
    
    
    (64
    )Porto Velho(2)
    
    
    (32
    )
    
    
    
    
    
    
    Manaus and Rio Negro
    
    
    (15
    )
    
    
    
    
    
    
    Central and other South American power investments
    
    
    (2
    )
    
    
    1
    
    
    
    (89
    )Enterprise
    
    
    
    
    
    
    
    
    
    
    183Javelina
    
    
    
    
    
    
    
    
    
    
    111KIECO
    
    
    
    
    
    
    
    
    
    
    108Other
    
    
    
    
    
    
    
    
    
    
    4$
    (50
    )
    
    $
    6
    
    
    $
    91
 
 (1)
    
    Amounts represent 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.(2)
    
    Amount does not include a $25 million impairment of our note receivable in 2007 as further described in Matters that Could Impact Our Investments,below.  Year Ended December 31,2007
    
    2006
    
    2005(In millions)Operating results data:Operating revenues
    
    $
    872
    
    
    $
    1,101
    
    
    $
    1,476Operating expenses
    
    
    528
    
    
    
    741
    
    
    
    1,407Income (loss) from continuing operations
    
    
    211
    
    
    
    174
    
    
    
    (163
    )Net income (loss)(1)
    
    
    211
    
    
    
    174
    
    
    
    (163
    )Financial position data:(2)Current assets
    
    $
    390
    
    
    $
    441
    
    
    $
    942Non-current assets
    
    
    2,323
    
    
    
    2,408
    
    
    
    3,423Short-term debt
    
    
    41
    
    
    
    82
    
    
    
    242Other current liabilities
    
    
    328
    
    
    
    321
    
    
    
    441Long-term debt
    
    
    519
    
    
    
    556
    
    
    
    1,171Other non-current liabilities
    
    
    588
    
    
    
    592
    
    
    
    632Minority interests
    
    
    
    
    
    
    
    
    
    
    83Redeemable preferred stock
    
    
    
    
    
    
    
    
    
    
    9Equity in net assets
    
    
    1,237
    
    
    
    1,298
    
    
    
    1,787
 
 (1)
    
    Includes net income (loss) of $(1) million, $20 million and $15 million in 2007, 2006 and 2005, related to our proportionate share of affiliates in which we hold greater than a 50 percent interest.(2)
    
    Includes total assets of $190 million and $417 million as of December 31, 2007 and 2006 related to our proportionate share of affiliates in which we hold greater than a 50 percent interest.   2007
    
    2006
    
    2005(In millions)Operating revenue(1)
    
    $
    7
    
    
    $
    64
    
    
    $
    114Cost of sales
    
    
    5
    
    
    
    3
    
    
    
    7Other income
    
    
    4
    
    
    
    6
    
    
    
    9Interest income(2)
    
    
    1
    
    
    
    46
    
    
    
    47
 
 (1)
    
    Decrease primarily due to the sale of investments in our Power segment.(2)
    
    Decrease primarily due to the impairment of our Porto Velho note receivable in 2007 as further described below. 131




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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.
  132




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##### Table of Contents



Manaus /Rio Negro.
 Asian and Central American power investments.
 Investment in Bolivia.
 Investment in Argentina.
 133




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##### Table of Contents



Supplemental Selected Quarterly Financial Information (Unaudited)
  Quarters EndedMarch 31
    
    June 30
    
    September 30
    
    December 31
    
    Total(In millions, except per common share amounts)2007Operating revenues
    
    $
    1,022
    
    
    $
    1,198
    
    
    $
    1,166
    
    
    $
    1,262
    
    
    $
    4,648Operating income
    
    
    335
    
    
    
    451
    
    
    
    417
    
    
    
    442
    
    
    
    1,645Earnings (losses) from unconsolidated affiliates
    
    
    37
    
    
    
    44
    
    
    
    (6
    )
    
    
    26
    
    
    
    101Income (loss) from continuing operations
    
    
    (48
    )
    
    
    169
    
    
    
    155
    
    
    
    160
    
    
    
    436Discontinued operations, net of income taxes
    
    
    677
    
    
    
    (3
    )
    
    
    
    
    
    
    
    
    
    
    674Net income
    
    
    629
    
    
    
    166
    
    
    
    155
    
    
    
    160
    
    
    
    1,110Net income available to common stockholders
    
    
    620
    
    
    
    156
    
    
    
    146
    
    
    
    151
    
    
    
    1,073Basic earnings per common shareIncome (loss) from continuing operations
    
    
    (0.08
    )
    
    
    0.23
    
    
    
    0.21
    
    
    
    0.22
    
    
    
    0.57Net income
    
    
    0.89
    
    
    
    0.23
    
    
    
    0.21
    
    
    
    0.22
    
    
    
    1.54Diluted earnings per common shareIncome (loss) from continuing operations
    
    
    (0.08
    )
    
    
    0.22
    
    
    
    0.20
    
    
    
    0.21
    
    
    
    0.57Net income
    
    
    0.89
    
    
    
    0.22
    
    
    
    0.20
    
    
    
    0.21
    
    
    
    1.532006Operating 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
    )
    
    
    0.64
  September 30, 2007.
 June 30, 2007.
 March 31, 2007.
 December 31, 2006.
 September 30, 2006.
 June 30, 2006.
 134




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##### Table of Contents



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

Egypt(1)
    
    

Worldwide2007Natural gas and oil properties:Costs subject to amortization
    
    $
    17,631
    
    
    $
    546
    
    
    $
    18,177Costs not subject to amortization
    
    
    474
    
    
    
    265
    
    
    
    73918,105
    
    
    
    811
    
    
    
    18,916Less accumulated depreciation, depletion and amortization
    
    
    11,847
    
    
    
    255
    
    
    
    12,102Net capitalized costs
    
    $
    6,258
    
    
    $
    556
    
    
    $
    6,8142006Natural 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
    
    
    $
    4,928
 
 (1)
    
    Capitalized costs for Egypt were $14 million and $4 million as of December 31, 2007 and 2006. Total Costs Incurred.
 United
    
    
    Brazil andStates
    
    

Egypt(1)
    
    

Worldwide2007Property acquisition costsProved properties
    
    $
    964
    
    
    $
    
    
    
    $
    964Unproved properties
    
    
    262
    
    
    
    5
    
    
    
    267Exploration costs
    
    
    398
    
    
    
    199
    
    
    
    597Development costs
    
    
    735
    
    
    
    26
    
    
    
    761Costs expended
    
    
    2,359
    
    
    
    230
    
    
    
    2,589Asset retirement obligation costs
    
    
    38
    
    
    
    7
    
    
    
    45Total costs incurred
    
    $
    2,397
    
    
    $
    237
    
    
    $
    2,634Unconsolidated investment in Four Star
    
    $
    27
    
    
    $
    
    
    
    $
    272006Property 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
    
    
    
    1,462
 135




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##### Table of Contents



United
    
    
    Brazil andStates
    
    

Egypt(1)
    
    

WorldwideAsset retirement obligation costs
    
    
    1
    
    
    
    
    
    
    
    1Total costs incurred
    
    $
    1,433
    
    
    $
    30
    
    
    $
    1,463Unconsolidated investment in Four Star(2)
    
    $
    769
    
    
    $
    
    
    
    $
    769
 
 (1)
    
    Costs incurred for Egypt were $10 million and $4 million for the years ended December 31, 2007 and 2006.(2)
    
    Amount includes deferred income tax adjustments of $179 million related to the acquisition of full-cost pool
properties and $217 million related to the acquisition of our unconsolidated investment in Four Star.   Unevaluated Capitalized Costs.
  Cumulative
    
    
    Costs Excluded
    
    
    CumulativeBalance
    
    
    for Years Ended(1)
    
    
    BalanceDecember 31,
    
    
    December 31
    
    
    December 31,2007
    
    
    2007
    
    
    2006
    
    
    2005
    
    
    2004United StatesAcquisition
    
    $
    418
    
    
    $
    235
    
    
    $
    30
    
    
    $
    126
    
    
    $
    27Exploration
    
    
    56
    
    
    
    37
    
    
    
    14
    
    
    
    3
    
    
    
    2Development
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Total United States
    
    
    474
    
    
    
    272
    
    
    
    44
    
    
    
    129
    
    
    
    29Brazil & EgyptAcquisition
    
    
    8
    
    
    
    3
    
    
    
    2
    
    
    
    
    
    
    
    3Exploration
    
    
    257
    
    
    
    193
    
    
    
    45
    
    
    
    9
    
    
    
    10Development
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Total Brazil & Egypt
    
    
    265
    
    
    
    196
    
    
    
    47
    
    
    
    9
    
    
    
    13Worldwide
    
    $
    739
    
    
    $
    468
    
    
    $
    91
    
    
    $
    138
    
    
    $
    42
 
 (1)
    
    Includes capitalized interest of $33 million, $24 million and $9 million for the years ended December 31, 2007, 2006 and 2005. Natural Gas and Oil Reserves.
  136




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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 Bcfe)ConsolidatedJanuary 1, 2005
    
    
    1,724
    
    
    
    69
    
    
    
    1,793
    
    
    
    27,331
    
    
    
    24,171
    
    
    
    51,502
    
    
    
    13,201
    
    
    
    2,181Revisions due to prices
    
    
    18
    
    
    
    4
    
    
    
    22
    
    
    
    945
    
    
    
    210
    
    
    
    1,155
    
    
    
    115
    
    
    
    30Revisions other than price
    
    
    (61
    )
    
    
    (6
    )
    
    
    (67
    )
    
    
    (685
    )
    
    
    7,717
    
    
    
    7,032
    
    
    
    1,033
    
    
    
    (19
    )Extensions and discoveries
    
    
    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 due to prices
    
    
    (48
    )
    
    
    
    
    
    
    (48
    )
    
    
    (1,007
    )
    
    
    
    
    
    
    (1,007
    )
    
    
    (152
    )
    
    
    (55
    )Revisions other than price
    
    
    56
    
    
    
    (1
    )
    
    
    55
    
    
    
    (507
    )
    
    
    (365
    )
    
    
    (872
    )
    
    
    (1,682
    )
    
    
    40Extensions and discoveries
    
    
    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
    
    
    
    2,415Revisions due to prices
    
    
    28
    
    
    
    
    
    
    
    28
    
    
    
    2,336
    
    
    
    10
    
    
    
    2,346
    
    
    
    154
    
    
    
    43Revisions other than price
    
    
    (39
    )
    
    
    (1
    )
    
    
    (40
    )
    
    
    3,711
    
    
    
    1,010
    
    
    
    4,721
    
    
    
    (35
    )
    
    
    (12
    )Extensions and discoveries
    
    
    296
    
    
    
    
    
    
    
    296
    
    
    
    5,876
    
    
    
    
    
    
    
    5,876
    
    
    
    1,681
    
    
    
    341Purchases of reserves in place
    
    
    339
    
    
    
    
    
    
    
    339
    
    
    
    3,111
    
    
    
    
    
    
    
    3,111
    
    
    
    
    
    
    
    357Sales of reserves in place
    
    
    (2
    )
    
    
    
    
    
    
    (2
    )
    
    
    (73
    )
    
    
    
    
    
    
    (73
    )
    
    
    
    
    
    
    (2
    )Production
    
    
    (238
    )
    
    
    (4
    )
    
    
    (242
    )
    
    
    (5,966
    )
    
    
    (157
    )
    
    
    (6,123
    )
    
    
    (1,698
    )
    
    
    (289
    )December 31, 2007
    
    
    2,248
    
    
    
    51
    
    
    
    2,299
    
    
    
    49,674
    
    
    
    32,710
    
    
    
    82,384
    
    
    
    10,114
    
    
    
    2,853Proved developed reservesDecember 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
    
    
    
    1,727December 31, 2007
    
    
    1,738
    
    
    
    19
    
    
    
    1,757
    
    
    
    35,070
    
    
    
    680
    
    
    
    35,750
    
    
    
    8,132
    
    
    
    2,020Unconsolidated investment in Four StarDecember 31, 2007Net proved developed and undeveloped reserves
    
    
    200
    
    
    
    
    
    
    
    200
    
    
    
    2,858
    
    
    
    
    
    
    
    2,858
    
    
    
    6,411
    
    
    
    256Proved developed reserves
    
    
    170
    
    
    
    
    
    
    
    170
    
    
    
    2,804
    
    
    
    
    
    
    
    2,804
    
    
    
    5,345
    
    
    
    219December 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
    
    
    
    187
     137




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138




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##### Table of Contents



Results of Operations.
 UnitedStates
    
    
    Brazil
    
    
    Worldwide2007Net RevenuesSales to external customers
    
    $
    1,085
    
    
    $
    25
    
    
    $
    1,110Affiliated sales
    
    
    1,149
    
    
    
    (8
    )
    
    
    1,141Total
    
    
    2,234
    
    
    
    17
    
    
    
    2,251Cost of products and services(1)
    
    
    (72
    )
    
    
    
    
    
    
    (72
    )Production costs(2)
    
    
    (327
    )
    
    
    (11
    )
    
    
    (338
    )Depreciation, depletion and amortization
    
    
    (748
    )
    
    
    (16
    )
    
    
    (764
    )1,087
    
    
    
    (10
    )
    
    
    1,077Income tax expense
    
    
    (392
    )
    
    
    4
    
    
    
    (388
    )Results of operations from producing activities
    
    $
    695
    
    
    $
    (6
    )
    
    $
    689Equity earnings from unconsolidated investment in Four Star
    
    $
    12
    
    
    $
    
    
    
    $
    12Depreciation, depletion and amortization ($/Mcfe)
    
    $
    2.63
    
    
    $
    3.10
    
    
    $
    2.642006Net 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
    
    $
    10
    
    
    $
    
    
    
    $
    10Depreciation, depletion and amortization ($/Mcfe)
    
    $
    2.37
    
    
    $
    2.14
    
    
    $
    2.362005Net 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
    
    
    $
    
    
    
    $
    19Depreciation, depletion and amortization ($/Mcfe)
    
    $
    2.25
    
    
    $
    2.31
    
    
    $
    2.26
 
 (1)
    
    Cost of products and services consists primarily of transportation costs.(2)
    
    Production costs include lease operating costs and production related taxes, including ad valorem and severance taxes.(3)
    
    Acquired in August 2005. 139




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Standardized Measure of Discounted Future Net Cash Flows.
 UnitedStates
    
    
    Brazil
    
    
    Worldwide2007Future cash inflows(1)
    
    $
    19,329
    
    
    $
    3,226
    
    
    $
    22,555Future production costs
    
    
    (4,822
    )
    
    
    (560
    )
    
    
    (5,382
    )Future development costs
    
    
    (1,805
    )
    
    
    (444
    )
    
    
    (2,249
    )Future income tax expenses
    
    
    (3,144
    )
    
    
    (625
    )
    
    
    (3,769
    )Future net cash flows
    
    
    9,558
    
    
    
    1,597
    
    
    
    11,15510% annual discount for estimated timing of cash flows
    
    
    (3,704
    )
    
    
    (617
    )
    
    
    (4,321
    )Standardized measure of discounted future net cash flows
    
    $
    5,854
    
    
    $
    980
    
    
    $
    6,834Standardized measure of discounted future net cash flows, including effects of hedging activities
    
    $
    5,902
    
    
    $
    980
    
    
    $
    6,8822006Future 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
    
    
    $
    6,308Unconsolidated Investment in Four StarStandardized measure of discounted future net cash flows2007
    
    $
    444
    
    
    $
    
    
    
    $
    4442006
    
    $
    323
    
    
    $
    
    
    
    $
    3232005
    
    $
    617
    
    
    $
    
    
    
    $
    617
 
 (1)
    
    United States excludes $61 million, $219 million and
$(502) million of future net cash inflows (outflows)
attributable to hedging activities in the years 2007, 2006
and 2005. Brazil excludes $4 million of future net cash
outflows attributable to hedging activities in 2005. 140




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Changes in Standardized Measure of Discounted Future Net Cash Flows.
 Years Ended December 31,(1)2007
    
    
    2006
    
    
    2005(In millions)Sales and transfers of natural gas and oil produced net of production costs
    
    $
    (1,657
    )
    
    $
    (1,516
    )
    
    $
    (1,477
    )Net changes in prices and production costs
    
    
    2,723
    
    
    
    (2,891
    )
    
    
    2,884Extensions, discoveries and improved recovery, less related costs
    
    
    910
    
    
    
    549
    
    
    
    793Changes in estimated future development costs
    
    
    (4
    )
    
    
    (55
    )
    
    
    2Previously estimated development costs incurred during the period
    
    
    200
    
    
    
    192
    
    
    
    247Revision of previous quantity estimates
    
    
    117
    
    
    
    (38
    )
    
    
    47Accretion of discount
    
    
    501
    
    
    
    827
    
    
    
    476Net change in income taxes
    
    
    (1,333
    )
    
    
    1,123
    
    
    
    (1,093
    )Purchases of reserves in place
    
    
    810
    
    
    
    4
    
    
    
    956Sale of reserves in place
    
    
    (7
    )
    
    
    (42
    )
    
    
    (83
    )Change in production rates, timing and other
    
    
    95
    
    
    
    (289
    )
    
    
    (333
    )Net change
    
    $
    2,355
    
    
    $
    (2,136
    )
    
    $
    2,419
 
 (1)
    
    This disclosure reflects changes in the standardized measure calculation excluding the effects of hedging activities. 141




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##### Table of Contents



SCHEDULE II
 
 EL PASO CORPORATION
VALUATION AND QUALIFYING ACCOUNTS
 Years Ended December 31, 2007, 2006 and 2005
(In millions)
 Balance at
    
    Charged to
    
    
    
    
    
    Charged
    
    Balance atBeginning
    
    Costs and
    
    
    
    
    
    to Other
    
    End ofDescription
    
    of Period
    
    Expenses
    
    Deductions
    
    Accounts
    
    Period2007Allowance for doubtful accounts
    
    $
    28
    
    
    $
    (4
    )
    
    $
    (5
    )
    
    $
    (2
    )
    
    $
    17Valuation allowance on deferred tax assets
    
    
    127
    
    
    
    10
    
    
    
    
    
    
    
    
    
    
    
    137Legal
reserves(7)
    
    
    548
    
    
    
    36
    
    
    
    (128
    )(2)
    
    
    4
    
    
    
    460Environmental reserves
    
    
    314
    
    
    
    21
    
    
    
    (75
    )
    
    
    
    
    
    
    260Regulatory reserves(3)
    
    
    65
    
    
    
    61
    
    
    
    (116
    )
    
    
    
    
    
    
    102006(1)Allowance for doubtful accounts
    
    $
    65
    
    
    $
    (5
    )
    
    $
    (27
    )(4)
    
    $
    (5
    )
    
    $
    28Valuation allowance on deferred tax assets
    
    
    107
    
    
    
    23
    
    
    
    
    
    
    
    (3
    )
    
    
    127Legal reserves(7)
    
    
    574
    
    
    
    48
    
    
    
    (74
    )
    
    
    
    
    
    
    548Environmental reserves
    
    
    348
    
    
    
    30
    
    
    
    (64
    )
    
    
    
    
    
    
    314Regulatory reserves(3)
    
    
    1
    
    
    
    65
    
    
    
    (1
    )
    
    
    
    
    
    
    652005(1)Allowance for doubtful accounts
    
    $
    195
    
    
    $
    (68
    )
    
    $
    (54
    )(4)
    
    $
    (8
    )
    
    $
    65Valuation allowance on deferred tax assets
    
    
    51
    
    
    
    34
    (5)
    
    
    
    
    
    
    22
    
    
    
    107Legal reserves(7)
    
    
    592
    
    
    
    496
    
    
    
    (516
    )(6)
    
    
    2
    
    
    
    574Environmental reserves
    
    
    349
    
    
    
    60
    
    
    
    (61
    )(6)
    
    
    
    
    
    
    348Regulatory reserves
    
    
    1
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1
 
 (1)
    
    Amounts reflect the reclassification of discontinued operations.(2)
    
    Included is the settlement of our shareholder litigation lawsuits.(3)
    
    In 2006 and 2007, we recorded reserves for rate refunds under EPNGs rate case which was settled in 2007 and refunds paid to customers.(4)
    
    In 2006, relates primarily to the sale of our accounts receivable under an accounts receivable sales program. In 2005, relates primarily to accounts written off.(5)
    
    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.(6)
    
    Relates primarily to payments for various litigation reserves (including $442 million related to the Western Energy Settlement), environmental remediation reserves or
revenue crediting and rate settlement reserves.(7)
    
    Amounts are net of related insurance receivables. 142




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##### Table of Contents



ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
  
 ITEM 9A. CONTROLS AND PROCEDURES
 Evaluation of Disclosure Controls and Procedures
  Changes in Internal Control over Financial Reporting
  
 ITEM 9B. OTHER INFORMATION
  143




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##### Table of Contents



PART III
 
 ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
   
 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
  144




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PART IV
 
 ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
 (a) The following documents are filed as a part of this report:
   PageReports of Independent Registered Public Accounting Firms
    
    
    81Consolidated Statements of Income
    
    
    86Consolidated Balance Sheets
    
    
    87Consolidated Statements of Cash Flows
    
    
    89Consolidated Statements of Stockholders Equity
    
    
    90Consolidated Statements of Comprehensive Income
    
    
    91Notes to Consolidated Financial Statements
    
    
    922.
    
    Financial statement schedules and supplementary information required to be submittedSchedule II  Valuation and Qualifying Accounts
    
    
    1423.
    
    Exhibits
  Undertaking
  145




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##### Table of Contents



SIGNATURES
  EL PASO CORPORATIONBy:
    /s/ Douglas L. FosheeDouglas L. FosheePresident and Chief Executive Officer  Signature
    
    Title
    
    Date/s/ Douglas L. Foshee

Douglas L. Foshee
    
    President, Chief Executive Officer
and Director (Principal Executive Officer)
    
    February 28, 2008/s/ D. Mark Leland

D. Mark Leland
    
    Executive Vice President and Chief Financial
Officer (Principal Financial Officer)
    
    February 28, 2008/s/ John R. Sult

John R. Sult
    
    Senior Vice President and Controller
(Principal Accounting Officer)
    
    February 28, 2008/s/ Ronald L. Kuehn, Jr.
    
    Chairman of the Board
    
    February 28, 2008Ronald L. Kuehn, Jr./s/ Juan Carlos Braniff
    
    Director
    
    February 28, 2008Juan Carlos Braniff/s/ James L. Dunlap
    
    Director
    
    February 28, 2008James L. Dunlap/s/ Robert W. Goldman
    
    Director
    
    February 28, 2008Robert W. Goldman/s/ Anthony W. Hall, Jr.
    
    Director
    
    February 28, 2008Anthony W. Hall, Jr./s/ Thomas R. Hix
    
    Director
    
    February 28, 2008Thomas R. Hix/s/ William H. Joyce
    
    Director
    
    February 28, 2008William H. Joyce/s/ Ferrell P. McClean
    
    Director
    
    February 28, 2008Ferrell P. McClean/s/ Steven J. Shapiro
    
    Director
    
    February 28, 2008Steven J. Shapiro/s/ J. Michael Talbert
    
    Director
    
    February 28, 2008J. Michael Talbert/s/ Robert F. Vagt
    
    Director
    
    February 28, 2008Robert F. Vagt/s/ John L. Whitmire
    
    Director
    
    February 28, 2008John L. Whitmire/s/ Joe B. Wyatt
    
    Director
    
    February 28, 2008Joe B. Wyatt
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##### Table of Contents



EL PASO CORPORATION
 EXHIBIT INDEX
December 31, 2007
  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 December 6, 2007 (Exhibit 3.B to our Form 8-K filed December 6, 2007).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, to Indenture dated as of May 10, 1999 (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, to Indenture dated as of May 10, 1999 (Exhibit 4.A to our 2006 Third Quarter
Form 10-Q).4.F
    
    Twelfth Supplemental Indenture dated as of June 18, 2007 between El Paso Corporation and HSBC Bank USA,
National Association, as trustee, to Indenture dated as of May 10, 1999 (Exhibit 4.A to our 2007 Second 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.A.1
    
    Amendment No. 1 effective as of January 1, 2007 to the 1995 Compensation Plan for Non-Employee Directors
Amended and Restated effective as of December 4, 2003.+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).+10.B.1
    
    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).*+10.B.2
    
    Amendment No. 2 effective as of February 7, 2001 to the Stock Option Plan for Non-Employee Directors.+10.B.3
    
    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);*+10.C.1
    
    Amendment No. 1 effective as of February 7, 2001 to the 2001 Stock Option Plan for Non-Employee Directors.*+10.C.2
    
    Amendment No. 2 effective as of December 4, 2003 to the 2001 Stock Option Plan for Non-Employee Directors.+10.C.3
    
    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
 147




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ExhibitNumber
    
    Description(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.*+10.E.1
    
    Amendment No. 1 effective as of February 7, 2001 to the 1999 Omnibus Incentive Compensation Plan.+10.E.2
    
    Amendment No. 2 effective as of May 1, 2003 to the 1999 Omnibus Incentive Compensation Plan (Exhibit 10.I.1 to
our 2003 Second Quarter Form 10-Q).+10.E.3
    
    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).*+10.F
    
    2001 Omnibus Incentive Compensation Plan effective as of January 29, 2001.*+10.F.1
    
    Amendment No. 1 effective as of February 7, 2001 to the 2001 Omnibus Incentive Compensation Plan.*+10.F.2
    
    Amendment No. 2 effective as of April 1, 2001 to the 2001 Omnibus Incentive Compensation Plan.*+10.F.3
    
    Amendment No. 3 effective as of July 17, 2002 to the 2001 Omnibus Incentive Compensation Plan.+10.F.4
    
    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).+10.F.5
    
    Amendment No. 5 effective as of March 8, 2004 to the 2001 Omnibus Incentive Compensation Plan (Exhibit 10.K.1
to our 2003 Form 10-K).+10.F.6
    
    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.*+10.G.1
    
    Amendment No. 1 effective as of November 7, 2002 to the Supplemental Benefits Plan.+10.G.2
    
    Amendment No. 2 effective as of June 1, 2004 to the Supplemental Benefits Plan (Exhibit 10.L.1 to our 2004 Form
10-K).+10.G.3
    
    Amendment No. 3 effective December 17, 2004 to the Supplemental Benefits Plan (Exhibit 10.UU to our 2004 Third
Quarter Form 10-Q).+10.G.4
    
    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.G.5
    
    Amendment No. 5 effective as of January 1, 2007 to the Supplemental Benefits Plan Amended and Restated
effective December 7, 2001.+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).*+10.H.1
    
    Amendment No. 1 effective as of February 7, 2001 to the Senior Executive Survivor Benefit Plan.*+10.H.2
    
    Amendment No. 2 effective as of October 1, 2002 to the Senior Executive Survivor Benefit Plan.+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).*+10.I.1
    
    Amendment No. 1 effective as of February 7, 2001 to the Key Executive Severance Protection Plan.*+10.I.2
    
    Amendment No. 2 effective as of November 7, 2002 to the Key Executive Severance Protection Plan.*+10.I.3
    
    Amendment No. 3 effective as of December 6, 2002 to the Key Executive Severance Protection Plan.+10.I.4
    
    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.I.5
    
    Amendment No. 5 effective as of January 1, 2007 to the Key Executive Severance Protection Plan Amended and
Restated effective as of August 1, 1998.+10.J
    
    2004 Key Executive Severance Protection Plan effective as of March 9, 2004 (Exhibit 10.P to our 2003 Form 10-K).*+10.J.1
    
    Amendment No. 1 effective as of January 1, 2007 to the 2004 Key Executive Severance Protection Plan effective
as of March 9, 2004.
 148




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##### Table of Contents



ExhibitNumber
    
    Description+10.K
    
    Director Charitable Award Plan Amended and Restated effective as of August 1, 1998 (Exhibit 10.P to our 2004
Form 10-K).*+10.K.1
    
    Amendment No. 1 effective as of February 7, 2001 to the Director Charitable Award Plan.+10.K.2
    
    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.*+10.L.1
    
    Amendment No. 1 effective as of February 7, 2001 to the Strategic Stock Plan.*+10.L.2
    
    Amendment No. 2 effective as of November 7, 2002 to the Strategic Stock Plan.*+10.L.3
    
    Amendment No. 3 effective as of December 6, 2002 to the Strategic Stock Plan.*+10.L.4
    
    Amendment No. 4 effective as of January 29, 2003 to the Strategic Stock Plan.+10.L.5
    
    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).*+10.N.1
    
    Termination of the Executive Award Plan of Sonat Inc.+10.N.2
    
    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).*+10.O
    
    Omnibus Plan for Management Employees Amended and Restated effective as of December 3, 1999.*+10.O.1
    
    Amendment No. 1 effective as of December 1, 2000 to the Omnibus Plan for Management Employees.*+10.O.2
    
    Amendment No. 2 effective as of February 7, 2001 to the Omnibus Plan for Management Employees.*+10.O.3
    
    Amendment No. 3 effective as of December 7, 2001 to the Omnibus Plan for Management.*+10.O.4
    
    Amendment No. 4 effective as of December 6, 2002 to the Omnibus Plan for Management Employees.+10.O.5
    
    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 (Exhibit 10.Z to our 2003 First Quarter
Form 10-Q); Supplement No. 1 to the Severance Pay Plan effective as of January 1, 2003 (Exhibit 10.Z to our
2003 First Quarter Form 10-Q); 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.P.1
    
    Amendment No. 1 effective January 1, 2007 to the Severance Pay Plan Amended and Restated effective as of
October 1, 2002.+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).
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ExhibitNumber
    
    Description+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 effective as of May 26, 2005 (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.Y.1
    
    Amendment No. 2 effective as of January 1, 2007 to the El Paso Corporation 2005 Compensation Plan for
Non-Employee Directors effective as of May 26, 2005.+10.Z
    
    El Paso Corporation 2005 Omnibus Incentive Compensation Plan effective as of May 26, 2005 (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.Z.1
    
    Amendment No. 3 to the El Paso Corporation 2005 Omnibus Incentive Compensation Plan effective as of May 26,
2005.+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).+10.BB
    
    2005 Supplemental Benefits Plan effective as of January 1, 2005 (Exhibit 10.KK to our 2005 Form 10-K).*+10.BB.1
    
    Amendment No. 1 effective as of January 1, 2007 to the 2005 Supplemental Benefits Plan effective as of January
1, 2005.10.CC
    
    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.DD
    
    Third Amended and Restated Credit Agreement dated as of November 16, 2007, among El Paso Corporation, El Paso
Natural Gas Company, Tennessee Gas Pipeline Company, the several banks and other financial institutions from
time to time parties thereto and JPMorgan Chase Bank, N.A., as administrative agent and as collateral agent
(Exhibit 10.A to our Form 8-K filed November 21, 2007).10.EE
    
    Third Amended and Restated Security Agreement dated as of November 16, 2007, made by among El Paso Corporation,
El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the Subsidiary Grantors and certain other credit
parties thereto and JPMorgan Chase Bank, N.A., not in its individual capacity, but solely as collateral agent
for the Secured Parties and as the depository bank (Exhibit 10.B to our Form 8-K filed November 21, 2007).10.FF
    
    Third Amended and Restated Subsidiary Guarantee Agreement dated as of November 16, 2007, made by each of the
Subsidiary Guarantors in favor of JPMorgan Chase Bank, N.A., as Collateral Agent (Exhibit 10.C to our Form 8-K
filed November 21, 2007).10.GG
    
    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.HH
    
    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.
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ExhibitNumber
    
    Description*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, 2007.*99.B
    
    Ryder Scott reserve report for Four Star Oil & Gas Company as of December 31, 2007.
 151