##### 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, 2008
 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
 o þ
 o þ
 þ o
 þ
  Large accelerated filer þ
Accelerated filer o
Non-accelerated filer o(Do not check if a smaller reporting company)
Smaller reporting company o 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




---



##### 



EL PASO CORPORATION
TABLE OF CONTENTS
 Caption
    
    Page
    
    PART I
    
    
    
    

Item 1.
    
    Business
    
    
    4Item 1A.
    
    Risk Factors
    
    
    29Item 1B.
    
    Unresolved Staff Comments
    
    
    41Item 2.
    
    Properties
    
    
    41Item 3.
    
    Legal Proceedings
    
    
    41Item 4.
    
    Submission of Matters to a Vote of Security Holders
    
    
    41PART IIItem 5.
    
    Market for Registrants Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities
    
    
    42Item 6.
    
    Selected Financial Data
    
    
    45Item 7.
    
    Managements Discussion and Analysis of Financial Condition and Results of Operations
    
    
    46Item 7A.
    
    Quantitative and Qualitative Disclosures About Market Risk
    
    
    83Item 8.
    
    Financial Statements and Supplementary Data
    
    
    86Item 9.
    
    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
    
    
    153Item 9A.
    
    Controls and Procedures
    
    
    153Item 9B.
    
    Other Information
    
    
    153PART IIIItem 10.
    
    Directors, Executive Officers and Corporate Governance
    
    
    154Item 11.
    
    Executive Compensation
    
    
    154Item 12.
    
    Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
    
    
    154Item 13.
    
    Certain Relationships and Related Transactions, and Director Independence
    
    
    154Item 14.
    
    Principal Accountant Fees and Services
    
    
    154PART IVItem 15.
    
    Exhibits and Financial Statement Schedules
    
    
    155Signatures
    
    
    156EX-4.HEX-4.IEX-10.A.IEX-10.CEX-10.E.2EX-10.F.4EX-10.F.5EX-10.I.4EX-10.PEX-10.P.2EX-10.REX-10.SEX-10.TEX-10.Y.1EX-10.BB.1EX-12EX-21EX-23.AEX-23.BEX-23.CEX-23.DEX-31.AEX-31.BEX-32.AEX-32.BEX-99.AEX-99.B




---



##### Table of Contents



/d
    
    =
    
    per dayBbl
    
    =
    
    barrelBBtu
    
    =
    
    billion British thermal unitsBcf
    
    =
    
    billion cubic feetBcfe
    
    =
    
    billion cubic feet of natural gas equivalentsKM
    
    =
    
    kilometerLNG
    
    =
    
    liquefied natural gasMBbls
    
    =
    
    thousand barrelsMcf
    
    =
    
    thousand cubic feetMcfe
    
    =
    
    thousand cubic feet of natural gas equivalentsMMBtu
    
    =
    
    million British thermal unitsMMcf
    
    =
    
    million cubic feetMMcfe
    
    =
    
    million cubic feet of natural gas equivalentsGWh
    
    =
    
    thousand megawatt hoursGW
    
    =
    
    gigawattsMW
    
    =
    
    megawattNGL
    
    =
    
    natural gas liquidsTBtu
    
    =
    
    trillion British thermal unitsTcfe
    
    =
    
    trillion cubic feet of natural gas equivalents
   3




---



##### Table of Contents



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




---



##### Table of Contents




    
    providing outstanding customer service;
    
    executing successfully on our backlog of committed expansion projects;
    
    developing new growth projects in our market and supply areas;
    
    ensuring the safety of our pipeline systems and assets;
    
    optimizing our contract portfolio; and
    
    focusing on efficiency and synergies across our systems.
 5




---



##### Table of Contents



Natural gas pipeline systems.
 As of December 31, 2008Transmission
    
    Supply and
    
    Ownership
    
    Miles of
    
    Design
    
    Storage
    
    Average Throughput(1)System
    
    Market Region
    
    Percentage
    
    Pipeline
    
    Capacity
    
    Capacity
    
    2008
    
    2007
    
    2006(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
    
    
    
    13,600
    
    
    
    7,069
    
    
    92(2)
    
    
    4,864
    
    
    
    4,880
    
    
    
    4,534El 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(3)
    
    
    44
    
    
    
    4,379
    
    
    
    4,189
    
    
    
    4,179Mojave 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)
    
    
    
    
    
    
    349
    
    
    
    458
    
    
    
    461Cheyenne Plains Gas
Pipeline (CPG)
    
    Extends from Cheyenne hub and
Yuma County in Colorado to
various pipeline
interconnections near
Greensburg, Kansas.
    
    
    100
    
    
    
    400
    
    
    
    934
    
    
    
    
    
    
    
    898
    
    
    
    735
    
    
    
    583
 
 (1)
    
    Includes throughput transported on behalf of affiliates.(2)
    
    Includes 29 Bcf of storage capacity from Bear Creek Storage Company (Bear
Creek) which TGP owns equally with Southern Natural Gas Company.(3)
    
    Reflects winter-sustainable west-flow capacity of 4,850 MMcf/d and
approximately 800 MMcf/d of east-end delivery capacity.(4)
    
    Reflects east to west flow capacity. 6




---



##### Table of Contents



As of December 31, 2008Transmission
    
    Supply and
    
    Ownership
    
    Miles of
    
    Design
    
    Storage
    
    Average Throughput(1)System
    
    Market Region
    
    Percentage
    
    Pipeline
    
    Capacity
    
    Capacity
    
    2008
    
    2007
    
    2006(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.
    
    
    94
    
    
    
    7,600
    
    
    
    3,700
    
    
    60(2)
    
    
    2,339
    
    
    
    2,345
    
    
    
    2,167Colorado 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.
    
    
    90
    
    
    
    4,100
    
    
    
    3,920
    
    
    
    29
    
    
    
    2,225
    
    
    
    2,339
    
    
    
    2,008Wyoming
Interstate
(WIC)
    
    Extends from western Wyoming,
eastern Utah, western Colorado
and the Powder River Basin to
various pipeline
interconnections near
Cheyenne, Wyoming.
    
    
    74
    
    
    
    800
    
    
    
    3,105
    
    
    
    
    
    
    
    2,543
    
    
    
    2,071
    
    
    
    1,914Florida Gas
Transmission
(FGT)(3)
    
    Extends from South Texas to
South Florida.
    
    
    50
    
    
    
    5,000
    
    
    
    2,100
    
    
    
    
    
    
    
    2,147
    
    
    
    2,056
    
    
    
    2,018Samalayuca
Pipeline and
Gloria a Dios
Compression
Station(4)
    
    Extends from U.S.-Mexico
border into the state of
Chihuahua, Mexico.
    
    
    50
    
    
    
    23
    
    
    
    460
    
    
    
    
    
    
    
    428
    
    
    
    462
    
    
    
    442San 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 29 Bcf of storage capacity from Bear Creek which SNG owns equally with
TGP.(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. Liquefied Petroleum Gas Pipeline System.
 WYCO Development Company (WYCO).
 7




---



##### Table of Contents



Underground Natural Gas Storage Facilities.
 As of December 31, 2008Ownership
    
    StorageStorage Entity
    
    Interest
    
    Capacity
    
    Location(Percent)
    
    (Bcf)Bear Creek
    
    
    100
    
    
    58(1)
    

    LouisianaYoung Gas Storage
    
    
    48
    
    
    
    6
    
    
    Colorado
 
 (1)
    
    Approximately 58 Bcf is contracted to affiliates. Amounts are not adjusted
for our ownership interest. Master Limited Partnership.
 FERC Approved Pipeline and Storage Expansion Projects.
 Pipeline Projects
 AnticipatedExisting
    
    Capacity
    
    
    
    Completion orProject
    
    System
    
    (MMcf/d)
    
    Description
    
    In-Service DateCarthage Expansion
    
    TGP
    
    
    98
    
    
    To install a new 7,700 horsepower
compressor station in DeSoto
Parish, Louisiana, abandon three
1,100 horsepower units and install
a 10,310 horsepower gas turbine
unit to upgrade and replace
compression at our existing
Compressor Station 47 located in
Ouachita Parish, Louisiana.
    
    May 2009Piceance Lateral Expansion
    
    WIC
    
    
    219
    
    
    To construct an additional 17,678
horsepower to increase capacity to
transport supply from the Piceance
Basin
    
    October 2009Concord Lateral Expansion
    
    TGP
    
    
    29
    
    
    To construct a new 6,130 horsepower
compressor station on our Line 200
system in Pelham, New Hampshire.
    
    November 2009Cypress Phase III(1)
    
    SNG
    
    
    161
    
    
    To add 20,700 horsepower of
additional compression on pipeline
facilities extending southward from
our Elba Island facility
    
    First half of 2011
 8




---



##### Table of Contents



Storage Projects
 AnticipatedStorage Capacity
    
    
    
    Completion orStorage Project
    
    (Bcf)
    
    Description
    
    In-Service DateBlack Warrior
Storage
    
    
    25
    
    
    To construct a multi-cycle natural
gas storage facility in Monroe and
Lowndes Counties, Mississippi. The
facilities will include three 8,000
horsepower electric driven
reciprocating compressor units, gas
processing and dehydration units
and a 4.6 mile, 24 inch pipeline
that will interconnect with our
system.
    

    (2)Totem Gas Storage(3)
    
    7(4)
    
    To develop a natural gas storage
field that services and
interconnects with the High Plains
Pipeline having 10.7 Bcf of natural
gas storage capacity, 7 Bcf of
which will be working gas capacity,
with a 200 MMcf/d maximum
withdrawal rate and 100 MMcf/d
maximum injection rate.
    
    July 2009
 
 (1)
    
    Construction of Cypress Phase III is at the option of BG LNG Services.(2)
    
    This project is not fully contracted and is not included in our inventory of committed
pipeline expansion projects at this time.(3)
    
    This joint project between us and an affiliate of PSCo will be
operated by us and owned by WYCO.(4)
    
    All of the working storage capacity is fully contracted with PSCo to cover the cost of
service (including a return on our investment) pursuant to a firm contract through 2040. LNG Facilities
 Elba Island LNG.
  Gulf LNG.
 Markets and Competition
   9




---



##### Table of Contents



10




---



##### Table of Contents



Customer Information
    
    Contract Information
    
    CompetitionTGPApproximately 470 firm and
interruptible customers.
    
    Approximately 510 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(736 BBtu/d)
    
    Expire in 2010-2027.EPNGApproximately 160 firm
and interruptible
customers
    
    Approximately 190
firm transportation
contracts. Weighted
average remaining
contract term of
approximately three
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 the southwestern U.S.
and northern Mexico were completed in 2008.Major Customers:
Sempra Energy and
Subsidiaries including
Southern California GasCompany (SoCal)
(130 BBtu/d)
(246 BBtu/d)
(323 BBtu/d)
    
    Expires
in 2009.
Expires in 2010.
Expires in 2011.ConocoPhillips Company
(447 BBtu/d)
(150 BBtu/d)
(392 BBtu/d)
    
    Expires 2009.
Expires 2010.
Expires 2012.Southwest Gas Corporation
(412 BBtu/d)
(75 BBtu/d)
    
    Expires in 2011.
Expires in 2015.
 11




---



##### Table of Contents



Customer Information
    
    Contract Information
    
    CompetitionMPCApproximately 10 firm and
interruptible customers
    
    Approximately five firm
transportation contracts.
Weighted average
remaining contract term
of approximately seven
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 the southwestern
U.S. and northern Mexico were
completed in 2008.Major Customer:EPNG
(312 BBtu/d)
    
    Expires
in 2015.CPGApproximately 40 firm and
interruptible customers
    
    Approximately 30
firm transportation
contracts. Weighted
average remaining
contract term of
approximately
eleven 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.
(195 BBtu/d)
    
    Expires
in 2015.Encana Marketing (USA)
Inc.
(170 BBtu/d)
    
    Expires in 2015.Anadarko Petroleum Corporation
(195 BBtu/d)
    
    Expire in 2015-2016.Shell Energy North America
US, L.P.
(125BBtu/d)
    
    Expires in 2019.
 12




---



##### Table of Contents



Customer Information
    
    Contract Information
    
    CompetitionSNGApproximately 270 firm and
interruptible customers
    
    Approximately 190 firm
transportation contracts.
Weighted average
remaining contract term
of approximately five
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(1)
(30 BBtu/d)
(152 BBtu/d)
(282 BBtu/d)
(545 BBtu/d)
    
    Expires
in 2009.
Expires in 2010.
Expires in 2011.
Expire in 2012-2015.Southern Company Services
(28 BBtu/d)
(390 BBtu/d)
    
    Expires in 2010.
Expire in 2017-2018.Alabama Gas Corporation
(39 BBtu/d)
(323 BBtu/d)
(31 BBtu/d)
    
    Expires in 2010.
Expires in 2011.
Expires in 2013.SCANA Corporation
(8 BBtu/d)
(161 BBtu/d)
(146 BBtu/d)
    
    Expires in 2009.
Expires in 2010.
Expire in 2017-2019.
 
 (1)
    
    Atlanta Gas Light Company is currently releasing a significant portion of its firm
capacity to a subsidiary of SCANA Corporation under terms allowed by our tariff. 13




---



##### Table of Contents



Customer Information
    
    Contract Information
    
    CompetitionCIGApproximately 120 firm and
    
    Approximately 170 firm
    
    CIG serves two major markets, aninterruptible customers
    
    transportation contracts.
    
    on-system market and anWeighted average
    
    off-system market. Its
on-systemremaining contract term
    
    market consists of utilities andof approximately eight
    
    other customers located along theyears.
    
    front range of the Rocky Mountains inColorado and Wyoming. Competitors inthis market consist of an intrastatepipeline, an interstate pipeline,local production from theDenver-Julesburg basin, and long-haulshippers who elect to sell into thismarket rather than the off-systemmarket. CIGs off-system marketconsists of the transportation ofRocky Mountain production frommultiple supply basins tointerconnections with other pipelinesbound for the midwest, the southwest,California and the Pacific northwest.Competition for this off-systemmarket consists of interstatepipelines that are directly connectedto its supply sources. CIG facescompetition from other existingpipelines and alternative energysources that are used to generateelectricity such as hydroelectricpower, wind, solar, coal and fueloil.Major Customers:PSCo(5 BBtu/d)
    
    Expires in 2009.(1,764 BBtu/d)
    
    Expire in 2012-2029.Williams Gas Marketing, Inc.(37 BBtu/d)
    
    Expires in 2009.(113 BBtu/d)
    
    Expires in 2010.(175 BBtu/d)
    
    Expires in 2011.(175 BBtu/d)
    
    Expires in 2013.Anadarko Petroleum Corporation(11 BBtu/d)
    
    Expires in 2009.(80 BBtu/d)
    
    Expires in 2010.(24 BBtu/d)
    
    Expires in 2011.(164 BBtu/d)
    
    Expire in 2012-2015.WICApproximately 50 firm and
    
    Approximately 70 firm
    
    WIC competes with existing pipelinesinterruptible customers
    
    transportation contracts.
    
    to provide transportation servicesWeighted average
    
    from supply basins in northwestremaining contract term
    
    Colorado, eastern Utah and Wyoming toof approximately eight
    
    pipeline interconnects in northeastyears.
    
    Colorado, and western Wyoming. WICfaces competition from other existingpipelines and alternative energysources that are used to generateelectricity such as hydroelectricpower, wind, solar, coal and fueloil.Major Customers:Williams Gas Marketing, Inc.(84 BBtu/d)
    
    Expires in 2010.(822 BBtu/d)
    
    Expire in 2013-2021.Anadarko Petroleum
Corporation(8 BBtu/d)
    
    Expires in 2009.(28 BBtu/d)
    
    Expires in 2010.(100 BBtu/d)
    
    Expires in 2011.(1014 BBtu/d)
    
    Expire in 2013-2023. 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.
 14




---



##### Table of Contents



Exploration and Production Segment
   United States
 Central.
 15




---



##### Table of Contents



2008Net
    
    Capital
    
    AverageArea
    
    Description
    
    Acres
    
    Investment
    
    Production(In millions)
    
    (MMcfe/d)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. Our operations are primarily in the
Bear Creek, Holly, Minden, Bald Prairie, Bethany
Longstreet and Logansport fields. We have new
production and development activities in several
fields in the Haynesville Shale. We also have
production and additional land positions in
Mississippi. In January 2009, we sold certain
natural gas producing properties in the Arklatex
area.
    
    149,000
    
    $385
    
    152Black WarriorBasin
    
    Established shallow coal bed methane producing areas of northwestern Alabama. We have high
average working interests in our operated
properties. In addition, we have a 50 percent
average working interest covering approximately
46,000 net acres operated by Black Warrior
Methane which produces from the Brookwood Field.
    
    111,000
    
    $50
    
    59Mid-Continent
    
    Primarily in Oklahoma with a focus on development projects in the Arkoma Basin where
we utilize horizontal drilling in the Hartshorne
Coals for coal bed methane production. We have
219,000 net acres in the Illinois Basin, focused
on the development of the New Albany Shale in
southwestern Indiana. We are the operator of
these properties and have a 95 percent working
interest in this area which is producing and
still under evaluation for further investment.
    
    518,000
    
    $59
    
    27
 Western.
 2008Net
    
    Capital
    
    AverageArea
    
    Description
    
    Acres
    
    Investment
    
    Production(In millions)
    
    (MMcfe/d)Rocky Mountains(Rockies)
    
    Primarily in Wyoming and Utah with a focus in the Powder River and Uintah basins, consisting
predominantly of operated oil fields utilizing
both primary and secondary recovery methods
combined with non-operated coal bed methane
fields. We own and 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.
    
    401,000
    
    $158
    
    78Raton Basin
    
    Primarily focused on coal bed methane production in the Raton Basin of northern New Mexico and
southern Colorado where we own the minerals
beneath 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. In January
2009, we sold our natural gas producing
properties in the San Juan Basin.
    
    606,000
    
    $82
    
    76
 16




---



##### Table of Contents



Texas Gulf Coast.
 2008Capital
    
    AverageArea
    
    Description
    
    Net Acres
    
    Investment
    
    Production(In millions)
    
    (MMcfe/d)Vicksburg/FrioTrends
    
    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
in Starr and Brooks counties with an average
working interest of over 83 percent.
    
    63,000
    
    $195
    
    128Upper Gulf Coast Wilcox
    
    Located onshore Texas Gulf Coast, including Renger, Dry Hollow, Brushy Creek and Speaks
fields located in Lavaca county, and
Graceland Field located in Colorado county.
    
    45,000
    
    $119
    
    33South TexasWilcox
    
    Includes 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.
    
    62,000
    
    $205
    
    64
 Gulf of Mexico and south Louisiana.
 2008Capital
    
    AverageArea
    
    Description
    
    Net Acres
    
    Investment
    
    Production(In millions)
    
    (MMcfe/d)Gulf of Mexico
    
    Primarily drilling interests in 82 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).
    
    275,000
    
    $215
    
    97South 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.
    
    13,000
    
    $33
    
    17
 Unconsolidated Investment in Four Star.
 17




---



##### Table of Contents



International
 Brazil.
 
    
    Camamu Basin.In 2008, we retained a 100 percent working interest in two development
areas in the BM-CAL-4 block, namely the Camarao and Pinauna Fields, and relinquished the
remainder of the acreage in the block. In Pinauna, we are in the process of obtaining
regulatory and environmental approvals that are required to enter the next phase of
development. In October 2008, IBAMA, the environmental regulatory agency in Brazil, issued
the Terms of Reference for the project to us, which represents the first major step in the
environmental permitting process. The timing of the Pinauna Field development will be
dependent on the receipt of all required regulatory approvals and either the recovery of
commodity prices or cost reductions that reflect the current low commodity price
environment.We also own an approximate 18 percent working interest in the BM-CAL-5 and BM-CAL-6 blocks
in the Camamu Basin, operated by Petrobras. In 2008, we participated in drilling an
exploratory well in the BM-CAL-6 block that was unsuccessful. We continue to evaluate other
opportunities in this block. We also participated in drilling an exploratory well in the
BM-CAL-5 block and found hydrocarbons. We are currently evaluating the results and appraisal
options on BM-CAL-5 and plan to participate in drilling a second exploratory well in the
block during 2009.
    
    Espirito Santo Basin.During 2008 and early 2009, we executed a unitization agreement
and gas and condensate sales agreements with Petrobras to develop the Camarupim Field which
was discovered in 2007. A unitization agreement is required to develop this field because
the field extends onto a block south of the ES-5 block in which we did not own a working
interest. Under the unitization agreement, we will own an approximate 24 percent working
interest in the Camarupim Field. The gas sales agreement provides for a price that adjusts
quarterly based on a basket of fuel oil prices, while the condensate sales agreement
provides for a price that adjusts monthly based on a Brent crude price less a fixed
differential that will adjust annually. The plan of development for the field includes
drilling four horizontal natural gas wells. As of December 31, 2008, one well has been
drilled and tested and two additional wells have been spud. We expect to complete all
drilling operations and begin production from the field in the second quarter of 2009.Also, in 2008, we participated with Petrobras in drilling an exploratory well in the ES-5
block in which we own a 35 percent working interest. Hydrocarbons were found in the well and
we are now evaluating the results. The exploratory well is located north of the Camarupim
Field. Petrobras plans to drill another exploratory well on this block during 2009.
    
    Potiguar Basin.We own a 35 percent working interest in the Pescada-Arabaiana Fields.
Our production from these fields averaged approximately 11 MMcfe/d in 2008. We also own an
interest in two blocks, BM-POT-11 and BM-POT-13, in the Potiguar Basin where we have no
proved reserves or production. In the second quarter of 2009, we expect to enter into an
agreement with Petrobras to relinquish our interest in these two blocks.
 Egypt.
 18




---



##### Table of Contents



Natural Gas and Oil Properties
 Natural Gas, Oil and Condensate and NGL Reserves and Production
  Net Proved Reserves
    
    2008Natural Gas
    
    Oil/Condensate
    
    NGL
    
    Total
    
    Production(MMcf)
    
    (MBbls)
    
    (MBbls)
    
    (MMcfe)
    
    (Percent)
    
    (MMcfe)Reserves and Production by
RegionUnited StatesCentral
    
    
    972,161
    
    
    
    2,560
    
    
    
    235
    
    
    
    988,933
    
    
    
    42
    %
    
    
    87,008Western
    
    
    628,133
    
    
    
    14,844
    
    
    
    38
    
    
    
    717,427
    
    
    
    31
    %
    
    
    56,429Texas Gulf Coast
    
    
    374,631
    
    
    
    2,548
    
    
    
    3,555
    
    
    
    411,248
    
    
    
    18
    %
    
    
    82,439Gulf of Mexico and south
Louisiana
    
    
    116,081
    
    
    
    3,958
    
    
    
    331
    
    
    
    141,819
    
    
    
    6
    %
    
    
    41,869Total United States
    
    
    2,091,006
    
    
    
    23,910
    
    
    
    4,159
    
    
    
    2,259,427
    
    
    
    97
    %
    
    
    267,745Brazil
    
    
    46,919
    
    
    
    3,180
    
    
    
    
    
    
    
    65,999
    
    
    
    3
    %
    
    
    3,928Total
    
    
    2,137,925
    
    
    
    27,090
    
    
    
    4,159
    
    
    
    2,325,426
    
    
    
    100
    %
    
    
    271,673Unconsolidated investment
in Four Star
    
    
    175,662
    
    
    
    2,199
    
    
    
    5,518
    
    
    
    221,962
    
    
    
    100
    %
    
    
    26,899Reserves by ClassificationUnited StatesProducing
    
    
    1,306,383
    
    
    
    13,834
    
    
    
    2,725
    
    
    
    1,405,741
    
    
    
    62
    %Non-Producing
    
    
    256,749
    
    
    
    5,965
    
    
    
    893
    
    
    
    297,900
    
    
    
    13
    %Undeveloped
    
    
    527,874
    
    
    
    4,111
    
    
    
    541
    
    
    
    555,786
    
    
    
    25
    %Total proved
    
    
    2,091,006
    
    
    
    23,910
    
    
    
    4,159
    
    
    
    2,259,427
    
    
    
    100
    %BrazilProducing
    
    
    8,802
    
    
    
    283
    
    
    
    
    
    
    
    10,500
    
    
    
    16
    %Non-Producing
    
    
    3,394
    
    
    
    332
    
    
    
    
    
    
    
    5,387
    
    
    
    8
    %Undeveloped
    
    
    34,723
    
    
    
    2,565
    
    
    
    
    
    
    
    50,112
    
    
    
    76
    %Total proved
    
    
    46,919
    
    
    
    3,180
    
    
    
    
    
    
    
    65,999
    
    
    
    100
    %WorldwideProducing
    
    
    1,315,185
    
    
    
    14,117
    
    
    
    2,725
    
    
    
    1,416,241
    
    
    
    61
    %Non-Producing
    
    
    260,143
    
    
    
    6,297
    
    
    
    893
    
    
    
    303,287
    
    
    
    13
    %Undeveloped
    
    
    562,597
    
    
    
    6,676
    
    
    
    541
    
    
    
    605,898
    
    
    
    26
    %Total proved
    
    
    2,137,925
    
    
    
    27,090
    
    
    
    4,159
    
    
    
    2,325,426
    
    
    
    100
    %Unconsolidated investment in
Four StarProducing
    
    
    145,794
    
    
    
    2,151
    
    
    
    4,488
    
    
    
    185,624
    
    
    
    84
    %Non-Producing
    
    
    2,996
    
    
    
    
    
    
    
    28
    
    
    
    3,165
    
    
    
    1
    %Undeveloped
    
    
    26,872
    
    
    
    48
    
    
    
    1,002
    
    
    
    33,173
    
    
    
    15
    %Total Four Star
    
    
    175,662
    
    
    
    2,199
    
    
    
    5,518
    
    
    
    221,962
    
    
    
    100
    %
   19




---



##### Table of Contents



Acreage and Wells
  Developed
    
    Undeveloped
    
    TotalGross(1)
    
    Net(2)
    
    Gross(1)
    
    Net(2)
    
    Gross(1)
    
    Net(2)AcreageUnited StatesCentral
    
    
    477,667
    
    
    
    287,364
    
    
    
    657,075
    
    
    
    490,862
    
    
    
    1,134,742
    
    
    
    778,226Western
    
    
    383,201
    
    
    
    294,054
    
    
    
    912,896
    
    
    
    713,236
    
    
    
    1,296,097
    
    
    
    1,007,290Texas Gulf Coast
    
    
    146,353
    
    
    
    95,956
    
    
    
    124,289
    
    
    
    73,953
    
    
    
    270,642
    
    
    
    169,909Gulf of Mexico and
south Louisiana
    
    
    147,849
    
    
    
    115,248
    
    
    
    209,726
    
    
    
    172,968
    
    
    
    357,575
    
    
    
    288,216Total United States
    
    
    1,155,070
    
    
    
    792,622
    
    
    
    1,903,986
    
    
    
    1,451,019
    
    
    
    3,059,056
    
    
    
    2,243,641Brazil
    
    
    72,281
    
    
    
    37,640
    
    
    
    1,103,321
    
    
    
    290,862
    
    
    
    1,175,602
    
    
    
    328,502Egypt
    
    
    
    
    
    
    
    
    
    
    1,225,000
    
    
    
    1,190,600
    
    
    
    1,225,000
    
    
    
    1,190,600Worldwide Total
    
    
    1,227,351
    
    
    
    830,262
    
    
    
    4,232,307
    
    
    
    2,932,481
    
    
    
    5,459,658
    
    
    
    3,762,743
 
 (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. 20




---



##### Table of Contents



Wells Being Drilled atNatural Gas
    
    Oil
    
    Total
    
    December 31, 2008Gross(1)
    
    Net(2)
    
    Gross(1)
    
    Net(2)
    
    Gross(1)
    
    Net(2)(3)
    
    Gross(1)
    
    Net(2)Productive WellsUnited StatesCentral
    
    
    3,591
    
    
    
    2,601
    
    
    
    17
    
    
    
    9
    
    
    
    3,608
    
    
    
    2,610
    
    
    
    32
    
    
    
    18Western
    
    
    1,389
    
    
    
    950
    
    
    
    452
    
    
    
    333
    
    
    
    1,841
    
    
    
    1,283
    
    
    
    2
    
    
    
    1Texas Gulf Coast
    
    
    1,498
    
    
    
    1,037
    
    
    
    
    
    
    
    
    
    
    
    1,498
    
    
    
    1,037
    
    
    
    10
    
    
    
    6Gulf of Mexico
and south
Louisiana
    
    
    64
    
    
    
    48
    
    
    
    33
    
    
    
    27
    
    
    
    97
    
    
    
    75
    
    
    
    2
    
    
    
    2Total
    
    
    6,542
    
    
    
    4,636
    
    
    
    502
    
    
    
    369
    
    
    
    7,044
    
    
    
    5,005
    
    
    
    46
    
    
    
    27Brazil
    
    
    5
    
    
    
    1
    
    
    
    5
    
    
    
    2
    
    
    
    10
    
    
    
    3
    
    
    
    4
    
    
    
    1Worldwide Total
    
    
    6,547
    
    
    
    4,637
    
    
    
    507
    
    
    
    371
    
    
    
    7,054
    
    
    
    5,008
    
    
    
    50
    
    
    
    28
 Net Exploratory(2)
    
    Net Development(2)2008
    
    2007
    
    2006
    
    2008
    
    2007
    
    2006Wells DrilledUnited StatesProductive
    
    
    163
    
    
    
    214
    
    
    
    106
    
    
    
    278
    
    
    
    238
    
    
    
    319Dry
    
    
    2
    
    
    
    12
    
    
    
    6
    
    
    
    7
    
    
    
    1
    
    
    
    2Total
    
    
    165
    
    
    
    226
    
    
    
    112
    
    
    
    285
    
    
    
    239
    
    
    
    321BrazilProductive
    
    
    
    
    
    
    3
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Dry
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Total
    
    
    
    
    
    
    3
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    WorldwideProductive
    
    
    163
    
    
    
    217
    
    
    
    106
    
    
    
    278
    
    
    
    238
    
    
    
    319Dry
    
    
    2
    
    
    
    12
    
    
    
    6
    
    
    
    7
    
    
    
    1
    
    
    
    2Total
    
    
    165
    
    
    
    229
    
    
    
    112
    
    
    
    285
    
    
    
    239
    
    
    
    321
 
 (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, 2008, we operated 4,534 of the 5,008 net productive
wells.  21




---



##### Table of Contents



Net Production, Sales Prices, Transportation and Production Costs
  2008
    
    
    2007
    
    
    2006Consolidated Volumes, Prices, and Costs per Unit:Net Production VolumesUnited StatesNatural gas (MMcf)
    
    
    229,518
    
    
    
    238,021
    
    
    
    213,262Oil, condensate and NGL (MBbls)
    
    
    6,371
    
    
    
    7,664
    
    
    
    7,439Total (MMcfe)
    
    
    267,745
    
    
    
    284,005
    
    
    
    257,899BrazilNatural gas (MMcf)
    
    
    3,185
    
    
    
    4,295
    
    
    
    7,140Oil, condensate and NGL (MBbls)
    
    
    124
    
    
    
    157
    
    
    
    247Total (MMcfe)
    
    
    3,928
    
    
    
    5,237
    
    
    
    8,619WorldwideNatural gas (MMcf)
    
    
    232,703
    
    
    
    242,316
    
    
    
    220,402Oil, condensate and NGL (MBbls)
    
    
    6,495
    
    
    
    7,821
    
    
    
    7,686Total (MMcfe)
    
    
    271,673
    
    
    
    289,242
    
    
    
    266,518Total (MMcfe/d)
    
    
    742
    
    
    
    792
    
    
    
    730Natural Gas Average Realized Sales Price ($/Mcf)United StatesExcluding hedges
    
    $
    8.51
    
    
    $
    6.60
    
    
    $
    6.77Including hedges
    
    $
    8.18
    
    
    $
    7.36
    
    
    $
    6.50BrazilExcluding hedges
    
    $
    2.60
    
    
    $
    2.61
    
    
    $
    2.61Including hedges
    
    $
    2.60
    
    
    $
    2.61
    
    
    $
    2.61WorldwideExcluding hedges
    
    $
    8.43
    
    
    $
    6.53
    
    
    $
    6.64Including hedges
    
    $
    8.10
    
    
    $
    7.28
    
    
    $
    6.38Oil, Condensate and NGL Average Realized Sales Price ($/Bbl)United StatesExcluding hedges
    
    $
    82.96
    
    
    $
    63.56
    
    
    $
    55.95Including hedges
    
    $
    77.74
    
    
    $
    63.56
    
    
    $
    55.95BrazilExcluding hedges
    
    $
    96.21
    
    
    $
    70.86
    
    
    $
    64.02Including hedges
    
    $
    96.21
    
    
    $
    41.27
    
    
    $
    54.48WorldwideExcluding hedges
    
    $
    83.21
    
    
    $
    63.71
    
    
    $
    56.21Including hedges
    
    $
    78.10
    
    
    $
    63.11
    
    
    $
    55.90Average Transportation CostsUnited StatesNatural gas ($/Mcf)
    
    $
    0.32
    
    
    $
    0.27
    
    
    $
    0.24Oil, condensate and NGL ($/Bbl)
    
    $
    0.98
    
    
    $
    0.83
    
    
    $
    0.85WorldwideNatural gas ($/Mcf)
    
    $
    0.31
    
    
    $
    0.27
    
    
    $
    0.23Oil, condensate and NGL ($/Bbl)
    
    $
    0.96
    
    
    $
    0.81
    
    
    $
    0.82
 22




---



##### Table of Contents



2008
    
    
    2007
    
    
    2006Average Production Costs ($/Mcfe)United StatesLease operating costs
    
    $
    0.89
    
    
    $
    0.86
    
    
    $
    0.97Production taxes
    
    
    0.44
    
    
    
    0.31
    
    
    
    0.28Total production costs
    
    $
    1.33
    
    
    $
    1.17
    
    
    $
    1.25BrazilLease operating costs
    
    $
    1.64
    
    
    $
    1.63
    
    
    $
    0.28Production taxes
    
    
    0.58
    
    
    
    0.51
    
    
    
    0.53Total production costs
    
    $
    2.22
    
    
    $
    2.14
    
    
    $
    0.81WorldwideLease operating costs
    
    $
    0.90
    
    
    $
    0.88
    
    
    $
    0.95Production taxes
    
    
    0.44
    
    
    
    0.31
    
    
    
    0.29Total production costs
    
    $
    1.34
    
    
    $
    1.19
    
    
    $
    1.24Unconsolidated affiliate volumes (Four Star)(1)Natural gas (MMcf)
    
    
    20,576
    
    
    
    19,380
    
    
    
    18,140Oil, condensate and NGL (MBbls)
    
    
    1,054
    
    
    
    1,015
    
    
    
    1,087Total equivalent volumes MMcfe
    
    
    26,899
    
    
    
    25,470
    
    
    
    24,663MMcfe/d
    
    
    74
    
    
    
    70
    
    
    
    68
 
 (1)
    
    Includes our proportionate share of volumes in Four Star. In 2007, we increased
our ownership interest in Four Star from 43 percent to 49 percent. Acquisition, Development and Exploration Expenditures
  2008
    
    
    2007
    
    
    2006(In millions)United StatesAcquisition Costs:Proved
    
    $
    51
    
    
    $
    964
    
    
    $
    2Unproved
    
    
    74
    
    
    
    262
    
    
    
    34Development Costs
    
    
    938
    
    
    
    735
    
    
    
    738Exploration Costs:Delay rentals
    
    
    6
    
    
    
    6
    
    
    
    6Seismic acquisition and reprocessing
    
    
    24
    
    
    
    19
    
    
    
    23Drilling
    
    
    408
    
    
    
    373
    
    
    
    294Asset Retirement Obligations
    
    
    19
    
    
    
    38
    
    
    
    3Total full cost pool expenditures
    
    
    1,520
    
    
    
    2,397
    
    
    
    1,100Non-full cost pool expenditures
    
    
    30
    
    
    
    13
    
    
    
    8Total costs incurred
    
    $
    1,550
    
    
    $
    2,410
    
    
    $
    1,108Acquisition of additional investment in Four Star(1)
    
    $
    
    
    
    $
    27
    
    
    $
    Brazil and Other International(2)Acquisition Costs:Proved
    
    $
    
    
    
    $
    
    
    
    $
    2Unproved
    
    
    1
    
    
    
    5
    
    
    
    1Development Costs
    
    
    93
    
    
    
    26
    
    
    
    40Exploration Costs:Seismic acquisition and reprocessing
    
    
    13
    
    
    
    6
    
    
    
    7Drilling
    
    
    91
    
    
    
    193
    
    
    
    46Asset Retirement Obligations
    
    
    
    
    
    
    7
    
    
    
    Total full cost pool expenditures
    
    
    198
    
    
    
    237
    
    
    
    96Non-full cost pool expenditures
    
    
    13
    
    
    
    1
    
    
    
    Total costs incurred
    
    $
    211
    
    
    $
    238
    
    
    $
    96
 23




---



##### Table of Contents



2008
    
    
    2007
    
    
    2006(In millions)Worldwide(2)Acquisition Costs:Proved
    
    $
    51
    
    
    $
    964
    
    
    $
    4Unproved
    
    
    75
    
    
    
    267
    
    
    
    35Development Costs
    
    
    1,031
    
    
    
    761
    
    
    
    778Exploration Costs:Delay rentals
    
    
    6
    
    
    
    6
    
    
    
    6Seismic acquisition and reprocessing
    
    
    37
    
    
    
    25
    
    
    
    30Drilling
    
    
    499
    
    
    
    566
    
    
    
    340Asset Retirement Obligations
    
    
    19
    
    
    
    45
    
    
    
    3Total full cost pool expenditures
    
    
    1,718
    
    
    
    2,634
    
    
    
    1,196Non-full cost pool expenditures
    
    
    43
    
    
    
    14
    
    
    
    8Total costs incurred
    
    $
    1,761
    
    
    $
    2,648
    
    
    $
    1,204Acquisition of additional investment in Four Star(1)
    
    $
    
    
    
    $
    27
    
    
    $
    
 
 (1)
    
    In 2007, we increased our ownership interest in Four Star from 43 percent to
49 percent.(2)
    
    Costs incurred for Egypt were $27 million, $10 million and $4 million for the
years ended December 31, 2008, 2007 and 2006.  Markets and Competition
   Regulatory Environment.
  24




---



##### Table of Contents



Marketing Segment
  Natural gas transportation-related contracts.
 Affiliated Pipelines(1)
    
    Other PipelinesDaily capacity (MMBtu/d)
    
    
    391,000
    
    
    
    198,000Expiration
    
    
    2010 to 2028
    
    
    
    2012 to 2026Receipt points / Delivery points
    
    Various
    
    Various
 
 (1)
    
    Primarily consists of contracts with TGP and EPNG. Legacy natural gas contracts.
 Legacy power contracts.
 Markets, Competition and Regulatory Environment
  25




---



##### Table of Contents



Power Segment
  El Paso
    
    
    
    
    
    
    
    
    
    ExpirationOwnership
    
    Gross
    
    
    
    
    
    Year of PowerPower Project
    
    Area
    
    Interest
    
    Capacity
    
    Power Purchaser
    
    Sales Contracts
    
    Fuel Type(Percent)
    
    (MW)Porto Velho(1)
    
    Brazil
    
    
    50
    
    
    
    404
    
    
    Eletronorte
    
    
    2010, 2023
    
    
    OilHabibullah
    
    Pakistan
    
    
    50
    
    
    
    136
    
    
    Pakistan Water and Power
    
    
    2029
    
    
    Natural Gas
 
 (1)
    
    We completed the sale of our investment in this project to our partner in February
2009. See Part II, Item 8, Financial Statements and Supplementary Data, Note 18 for a further discussion of the sale of this
investment.  El Paso Ownership
    
    
    
    
    
    Average 2008Pipeline
    
    Gross KM(2)
    
    Interest
    
    Design Capacity(2)
    
    Throughput(2)(Percent)
    
    (MMcf/d)
    
    (BBtu/d)Bolivia to Brazil
    
    
    3,150
    
    
    
    8
    
    
    
    1,059
    
    
    
    1,054Argentina to Chile(1)
    
    
    540
    
    
    
    22
    
    
    
    138
    
    
    
    210
 
 (1)
    
    We are currently in negotiations to sell our investment in this pipeline and expect the
sale to close in the first half of 2009.(2)
    
    Amounts are not adjusted for our ownership percentage. Environmental
  Employees
  26




---



##### Table of Contents



Executive Officers of the Registrant
  OfficerName
    
    Office
    
    Since
    
    AgeDouglas L. Foshee
    
    President and Chief Executive Officer of El Paso
    
    
    2003
    
    
    
    49D. Mark Leland
    
    Executive Vice President and Chief Financial Officer of El Paso
    
    
    2005
    
    
    
    47Robert W. Baker
    
    Executive Vice President and General Counsel of El Paso
    
    
    2002
    
    
    
    52Brent J. Smolik
    
    Executive Vice President of El Paso and President of El Paso
Exploration & Production Company
    
    
    2006
    
    
    
    47Susan B. Ortenstone
    
    Senior Vice President (Human Resources and Administration) of El Paso
    
    
    2003
    
    
    
    52James C. Yardley
    
    Executive Vice President, Pipeline Group
    
    
    2005
    
    
    
    57James J. Cleary
    
    President of Western Pipeline Group
    
    
    2005
    
    
    
    54
     27




---



##### Table of Contents



Available Information
  28




---



##### 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;
    
    price competition;
    
    expiration or turn back of significant contracts;
    
    changes in regulation and action of regulatory bodies;
    
    weather conditions that impact natural gas throughput and storage levels;
 29




---



##### Table of Contents




    
    weather fluctuations or warming or cooling trends that may impact demand in the markets
in which we do business, including trends potentially attributed to climate change;
    
    drilling activity and decreased availability of conventional gas supply sources and the
availability and timing of other natural gas supply sources, such as LNG;
    
    continued development of additional sources of gas supply that can be accessed;
    
    decreased natural gas demand due to various factors, including economic recession (as
further discussed below) and increases in
prices;
    
    legislative, regulatory, or judicial actions, such as mandatory greenhouse gas
regulations and/or legislation that could result in (i) changes in the demand for natural
gas and oil, (ii) changes in the availability of or demand for alternative energy sources
such as hydroelectric and nuclear power, wind and solar energy and/or
(iii) changes in the demand for less carbon intensive energy sources;
    
    availability and cost to fund ongoing maintenance and growth projects, especially in
periods of prolonged economic decline;
    
    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;
 30




---



##### Table of Contents




    
    reduced demand and market conditions in the areas we serve;
    
    the availability of alternative energy sources or natural gas supply points;
    
    legislative and/or regulatory actions.
 Fluctuations in energy commodity prices could adversely affect our pipeline businesses.
   
    
    regional, domestic and international supply and demand;
    
    availability and adequacy of transportation facilities;
    
    energy legislation and regulation;
    
    federal and state taxes, if any, on the sale or transportation of natural gas and NGL;
    
    abundance of supplies of alternative energy sources; and
    
    political unrest among 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 access sufficient capital at reasonable rates to fund expansion
projects, especially in periods of prolonged economic decline when we may be unable to
access the capital markets;
    
    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;
 31




---



##### Table of Contents




    
    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/or demand; and
    
    the lack of transportation, storage or throughput commitments.
  Our pipeline systems depend on certain key customers and producers for a significant portion of
their revenues. The loss of any of these key customers could result in a decline in our
systems revenues and cash available to pay distributions.
  We are exposed to the credit risk of our pipeline customers and our credit risk management may
not be adequate to protect against such risk.
  We are exposed to the credit and performance risk of our key contractors and suppliers.
  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 supply and/or demand for natural gas and oil especially during periods of
prolonged economic decline;
    
    the availability and reliability of commodity processing, gathering and pipeline
capacity;
 32




---



##### Table of Contents




    
    the level of imports of, and the price of, foreign natural gas and oil;
    
    the ability of certain foreign countries to agree to and maintain natural gas and oil
prices, production and export 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 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;
    
    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;
 33




---



##### Table of Contents




    
    declines in production volumes, including those from the Gulf of Mexico; and
    
    continued access to sufficient capital at reasonable rates to fund drilling programs to
develop and replace a reserve base with rapid depletion characteristics especially in
periods of prolonged economic decline when we may be unable to access the capital markets.
 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.
   34




---



##### Table of Contents



The success of our exploration and production business depends upon our ability to replace
reserves that we produce.
  We face competition from third parties to acquire and develop natural gas and oil reserves.
  Our use of derivative financial instruments could result in financial losses.
   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;
 35




---



##### Table of Contents




    
    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 governmental investigations could be materially adverse to us.
  The agencies that regulate our pipeline businesses and their customers could affect our
profitability.
    36




---



##### Table of Contents



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;
    
    receiving regulatory approval for remediation programs;
    
    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.
  37




---



##### Table of Contents



Costs of litigation matters and other contingencies could exceed our estimates.
  Risks Related to Our Liquidity
 We have significant debt and below investment grade credit ratings, which have impacted and will
continue to impact our financial condition, results of operations and liquidity.
  38




---



##### Table of Contents



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.
   Adverse general global economic conditions could negatively affect our operating results,
financial condition, liquidity or our share price.
   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.
  39




---



##### Table of Contents



Our available liquidity could be impacted by decreases in our natural gas and oil reserves under
our borrowing base facility of our exploration and production subsidiary.
  Our ability to sell assets or obtain partners on projects to maintain adequate liquidity may be
impacted by adverse general economic conditions.
  40




---



##### Table of Contents



ITEM 1B. UNRESOLVED STAFF COMMENTS
  
 ITEM 2. PROPERTIES
   
 ITEM 3. LEGAL PROCEEDINGS
  Natural Buttes.
 
 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
  41




---



##### Table of Contents



PART II
 
 ITEM 5.
    
    MARKET FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF
EQUITY SECURITIES.
  Quarterly Stock Prices.
 High
    
    Low
    
    Dividends2008Fourth Quarter
    
    $
    12.57
    
    
    $
    5.32
    
    
    $
    0.05Third Quarter
    
    
    22.47
    
    
    
    11.25
    
    
    
    0.05Second Quarter
    
    
    22.10
    
    
    
    15.80
    
    
    
    0.04First Quarter
    
    
    18.27
    
    
    
    14.83
    
    
    
    0.042007Fourth 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
    
    
    
    0.04
 Stock Performance Graph.
 42




---



##### Table of Contents



COMPARISON OF ANNUAL CUMULATIVE TOTAL RETURNS
 
 12/03
    
    12/04
    
    12/05
    
    12/06
    
    12/07
    
    12/08El Paso Corporation
    
    $
    100
    
    
    $
    129.40
    
    
    $
    153.48
    
    
    $
    195.07
    
    
    $
    222.26
    
    
    $
    102.42S&P 500 Stock Index
    
    $
    100
    
    
    $
    110.88
    
    
    $
    116.33
    
    
    $
    134.70
    
    
    $
    142.10
    
    
    $
    89.53S&P 500 Oil & Gas
Storage &
Transportation
Index(1)
    
    $
    100
    
    
    $
    139.91
    
    
    $
    184.82
    
    
    $
    219.84
    
    
    $
    251.14
    
    
    $
    124.82New Peer Group
    
    $
    100
    
    
    $
    128.47
    
    
    $
    179.67
    
    
    $
    193.25
    
    
    $
    248.82
    
    
    $
    163.03Old Peer Group
    
    $
    100
    
    
    $
    125.49
    
    
    $
    163.97
    
    
    $
    185.25
    
    
    $
    232.93
    
    
    $
    159.00
 
 (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.
 43




---



##### Table of Contents



Unregistered Sales of Equity Securities and Use of Proceeds.
 Approximate DollarTotal Number of
    
    Value of SharesShares Purchased as
    
    that May Yet BeTotal Number
    
    Average Price
    
    Part of Publicly
    
    PurchasedPeriod
    
    of Shares Purchased
    
    Paid per Share
    
    Announced Program
    
    Under the ProgramYear Ended December 31, 2008(1)
    
    
    4,663,053
    
    
    $
    16.62
    
    
    
    4,663,053
    
    
    $
    222,511,157
 
 (1)
    
    On May 14, 2008, the Board approved a $300 million stock repurchase program to
be consummated to the extent that we generate cash in excess of that originally planned. The
share repurchase program was publicly announced on May 15, 2008 and has no stated expiration
date. There was no activity in the fourth quarter of 2008. Other.
 Odd-lot Sales Program.
 44




---



##### Table of Contents



ITEM 6: SELECTED FINANCIAL DATA
  As of or for the Year Ended December 31,2008
    
    2007
    
    2006
    
    2005
    
    2004(In millions, except per common share amounts)Operating Results Data:Operating revenues
    
    $
    5,363
    
    
    $
    4,648
    
    
    $
    4,281
    
    
    $
    3,359
    
    
    $
    4,783Income (loss) from continuing operations
    
    $
    (823
    )
    
    $
    436
    
    
    $
    531
    
    
    $
    (506
    )
    
    $
    (1,032
    )Net income (loss) available to common stockholders
    
    $
    (860
    )
    
    $
    1,073
    
    
    $
    438
    
    
    $
    (633
    )
    
    $
    (947
    )Basic earnings (loss) per common share from
continuing operations
    
    $
    (1.24
    )
    
    $
    0.57
    
    
    $
    0.73
    
    
    $
    (0.82
    )
    
    $
    (1.61
    )Diluted earnings (loss) per common share from
continuing operations
    
    $
    (1.24
    )
    
    $
    0.57
    
    
    $
    0.72
    
    
    $
    (0.82
    )
    
    $
    (1.61
    )Cash dividends declared per common share
    
    $
    0.18
    
    
    $
    0.16
    
    
    $
    0.16
    
    
    $
    0.16
    
    
    $
    0.16Basic average common shares outstanding
    
    
    696
    
    
    
    696
    
    
    
    678
    
    
    
    646
    
    
    
    639Diluted average common shares outstanding
    
    
    696
    
    
    
    699
    
    
    
    739
    
    
    
    646
    
    
    
    639Financial Position Data:Total assets
    
    $
    23,668
    
    
    $
    24,579
    
    
    $
    27,261
    
    
    $
    31,840
    
    
    $
    31,398Long-term financing obligations, less current
maturities
    
    
    12,818
    
    
    
    12,483
    
    
    
    13,329
    
    
    
    16,282
    
    
    
    17,506Minority interests
    
    
    561
    
    
    
    565
    
    
    
    31
    
    
    
    31
    
    
    
    367Stockholders equity
    
    
    4,035
    
    
    
    5,280
    
    
    
    4,186
    
    
    
    3,389
    
    
    
    3,438
 Factors Affecting Trends.
 45




---



##### Table of Contents



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.
  
    
    Continuing to successfully execute on our backlog of committed expansion projects
and develop 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, terms of service,
and expansion projects; and
    
    Improving operating efficiency.
 46




---



##### Table of Contents




    
    Long-term growth of 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.
  Summary of 2008 Financial and Operational Performance
    Area of Operations
    
    Significant HighlightsPipelines
    
    Completed several pipeline projects and entered into new expansion projects
including our Ruby pipeline project, TGP 300 Line
project and FGT phase VIII Project resulting in a current backlog of committed
growth projects of approximately $8 billionPlaced several expansion projects in service including
the WIC Kanda lateral, Phase II of the Cypress
pipeline project, Cheyenne Plains compression
expansion, Southeast Supply Header Phase I expansion,
Medicine Bow expansion, High Plains Pipeline, and
Bluewater reconfiguration projectExploration and
Production
    
    Achieved an overall drilling success rate of 98 percentAdvanced growth opportunities domestically in the
Niobrara Shale in the Raton Basin, the Haynesville
Shale in Arklatex and the Altamont field in the
Rockies and internationally through our exploration
programs in Brazil and Egypt. In 2008 and early 2009,
we executed a unitization agreement and gas and
condensate sales agreements with Petrobras to develop
the Camarupim Field in BrazilHigh graded our asset portfolio through the sale of
certain non-core properties (primarily in our Texas
Gulf Coast and Gulf of Mexico regions) and acquired
interests in domestic natural gas and oil properties
in the Western region that complement our existing
asset portfolioManaged price risk through derivative contracts which,
when combined with our other positions, provided
higher realized commodity prices in 2008 and gives us
price protection on a significant portion of our
planned 2009 equivalent production
  47




---



##### Table of Contents



Outlook for 2009
   Liquidity and Capital
Resources Liquidity and Capital
Resources
    
    
    Capital Expenditures.Planned 2009 capital expenditures between
approximately $2.6 billion to $3.1 billion, with $1.7 billion of capital being spent in our
pipeline business and $0.9 billion to $1.3 billion in our exploration and production
business. Our $1.7 billion of planned pipeline capital reflects equity
partnering on one or more of our expansion projects.
    
    Asset Sales.We have sold or are evaluating the sale of several non-core assets
generating cash proceeds of approximately $0.4 billion in 2009, of which approximately $0.2
billion have already been completed.
 48




---



##### Table of Contents




    
    Other Liquidity Sources.We will continue to be opportunistic in generating additional
liquidity. In February 2009, we settled our 2009 crude oil production hedges generating $186
million of cash. Additionally, to the extent any of the asset sales or partnering
opportunities on expansion projects are delayed or cannot be completed, there is a further
decline in commodity prices or we experience other major disruptions in the financial
markets, we could also pursue other alternatives, including additional reductions in our
discretionary capital program, additional secured financing arrangements, seeking additional partners
for one or more of our other growth projects or selling additional non-core assets.
  
    
    Debt Capital Structure.Our debt capital structure is
80 percent fixed interest rates and 20 percent
floating interest rates. Accordingly, we believe we have lessened exposure to market
changes in interest rates on our existing debt which impact our interest costs.
    
    Revenue and Price Sensitivities. In our pipeline business, approximately three-fourths
of our pipeline revenues are collected in the form of demand or reservation charges. As a
result, near-term declines in demand for natural gas due to recessionary pressures or
declines in natural gas prices do not significantly impact pipeline revenues. Our
exploration and production business, however, is impacted by fluctuations in commodity
prices, although this is mitigated somewhat by derivative contracts
in place in 2009 representing approximately 75 percent of our domestic natural gas
production. Additionally, in the event of lower oil or natural gas prices, we currently
have unencumbered exploration and production properties and reserves that we could pledge as collateral
to maintain our current available borrowing base under the revolving credit facilities at
our exploration and production subsidiary.
    
    Counterparty Risk.We continually monitor the financial situation of our major lenders,
trading counterparties, customers, joint interest partners, vendors and suppliers, and
enforce our contractual rights with regard to providing collateral or credit. Certain of
our contractual arrangements with such parties include requirements to provide letters of
credit, performance bonds or other assurances of performance to mitigate, in part, the risk
of non-performance by such parties. However, our natural gas and oil
hedges executed in our exploration and production business do not contractually require the posting
of margin.
    
    Lending Institutions.As part of our determination of available capacity under our
credit agreements, we completed an assessment of our available lenders under these
facilities, which is a diverse group. Based on our assessment, we have determined the
potential exposure to a loss of available capacity to be approximately $28 million from El
Pasos $1.5 billion revolving credit facility, approximately $2 million from EPEPs $1.0
billion revolving credit facility, and approximately $15 million under EPBs $750 million
credit facility. This assessment was based upon the fact that one of our lenders has failed
to fund previous requests under these facilities and has filed for bankruptcy.
  49




---



##### Table of Contents



Results of Operations
 Overview
    2008
    
    
    2007
    
    
    2006(In millions)SegmentPipelines
    
    $
    1,273
    
    
    $
    1,265
    
    
    $
    1,187Exploration and Production
    
    
    (1,448
    )
    
    
    909
    
    
    
    640Marketing
    
    
    (104
    )
    
    
    (202
    )
    
    
    (71
    )Power
    
    
    1
    
    
    
    (37
    )
    
    
    82Segment EBIT
    
    
    (278
    )
    
    
    1,935
    
    
    
    1,838Corporate and other
    
    
    124
    
    
    
    (283
    )
    
    
    (88
    )Consolidated EBIT
    
    
    (154
    )
    
    
    1,652
    
    
    
    1,750Interest and debt expense
    
    
    (914
    )
    
    
    (994
    )
    
    
    (1,228
    )Income taxes
    
    
    245
    
    
    
    (222
    )
    
    
    9Income (loss) from continuing operations
    
    
    (823
    )
    
    
    436
    
    
    
    531Discontinued operations, net of income taxes
    
    
    
    
    
    
    674
    
    
    
    (56
    )Net income (loss)
    
    $
    (823
    )
    
    $
    1,110
    
    
    $
    475
  50




---



##### 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.
    
    76Usage 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.
    
    24
    Percent of Total
    
    
    
    
    
    
    Percent of TotalBBtu/d
    
    
    Contracted Capacity
    
    
    Reservation Revenue
    
    
    Reservation Revenue(In millions)2009
    
    
    2,600
    
    
    
    10
    
    
    $
    151
    
    
    
    72010
    
    
    3,497
    
    
    
    13
    
    
    
    287
    
    
    
    142011
    
    
    3,104
    
    
    
    12
    
    
    
    294
    
    
    
    152012
    
    
    3,928
    
    
    
    15
    
    
    
    241
    
    
    
    122013
    
    
    3,278
    
    
    
    13
    
    
    
    248
    
    
    
    122014 and beyond
    
    
    9,613
    
    
    
    37
    
    
    
    819
    
    
    
    40Total
    
    
    26,020
    
    
    
    100
    
    
    $
    2,040
    
    
    
    100
 51




---



##### Table of Contents



Summary of Operational and Financial Performance
    Project
    
    Anticipated In-Service Dates
    
    
    Estimated Costs
    
    
    FERC Approved(in millions)2009:Carthage Expansion
    
    May 2009
    
    $
    39
    
    
    YesTotem Gas Storage (50%)(1)
    
    July 2009
    
    
    77
    
    
    YesConcord Lateral Expansion
    
    November 2009
    
    
    21
    
    
    YesWIC Piceance Lateral Expansion
    
    October 2009
    
    
    62
    
    
    Yes2010 and Beyond:CIG Raton 2010 Expansion
    
    June 2010
    
    
    146
    
    
    NoWIC System Expansion(2)
    
    Various
    
    
    71
    
    
    NoCypress Phase III(3)
    
    First half of 2011
    
    
    86
    
    
    YesRuby
Pipeline(5)
    
    First Quarter of 2011
    
    
    3,000
    
    
    NoFGT Phase
VIII Expansion
(50%)(1)(5)
    
    April 2011
    
    
    1,200
    
    
    NoGulf LNG Clean Energy (50%)(4) (1)
    
    October 2011
    
    
    797
    
    
    YesTGP 300 Line Expansion
    
    November 2011
    
    
    750
    
    
    NoElba Expansion III and Elba Express
    
    2010-2014
    
    
    1,120
    
    
    YesSouth System III and Southeast SupplyHeader  Phase II
    
    2011-2012
    
    
    421
    
    
    NoTotal Committed Expansion Backlog
    
    
    
    
    
    $
    7,790
 
 (1)
    
    Amounts represent our share of the estimated costs.(2)
    
    This expansion consists of two projects with separate in-service dates of November 2010 and March 2011.(3)
    
    Construction of Cypress Phase III is at the option of BG LNG Services.(4)
    
    Includes approximately $295 million that we paid to acquire a 50 percent interest in this project.(5)
    
    Although these projects have substantial contractual
commitments with customers, they are not fully contracted. 52




---



##### Table of Contents




    
    South System III.The South System III expansion project will be completed in three
phases. During the second quarter of 2008, we changed the scope of this project at the
request of the customer which increased the total estimated cost to $352 million. We filed
an application with the FERC in December 2008 for certificate authorization to construct
and operate these facilities.
    
    Southeast Supply Header.We own an undivided interest in the northern portion of the
Southeast Supply Header project jointly owned by Spectra Energy Corp. (Spectra) and
Centerpoint Energy. The construction of this project is managed by Spectra and our share
of the estimated cost for this project is $241 million. This project is expected to be
completed in two phases. Phase I of the project was completed in September 2008. In December 2008, we filed an application with the FERC for certificate authorization to construct
Phase
II, which is anticipated to be complete in June 2011.
    
    Florida Gas Transmission Phase VIII.We have a 50 percent interest in this project
through our equity investment in Citrus. Our proportional share of the estimated cost of
this project increased in 2008 to $1.2 billion due to higher than expected pipe and other
costs.
    
    CIG Raton 2010 Expansion. In July 2008, we announced the expansion of the CIG Raton
Basin Pipeline extending from the Raton Basin Wet Canyon Lateral to the south end of the
Valley Line. The tentative FERC filing date for this project is March 2009.
    
    Ruby Pipeline Project.In 2008, we obtained sufficient long-term capacity commitments
from customers and committed to move forward with the $3 billion Ruby Pipeline project. We
filed a certificate application with the FERC in January 2009. We have ordered all of the
pipe for our Ruby Pipeline project on a fixed price basis which will
be recoverable through future rates when the project is placed in
service.
    
    TGP 300 Line Expansion.In August 2008, we announced our 300 Line expansion project
with an estimated total capital cost of approximately $750 million. We have ordered all of
the pipe for our TGP 300 Line expansion project on a fixed price basis which will be recoverable through future rates when the project is placed in
service.
    
    Gulf LNG Clean Energy.In February 2008, we completed our acquisition of a 50 percent
interest in the Gulf LNG Clean Energy Project, which is constructing a FERC approved
liquefied natural gas terminal in Pascagoula, Mississippi.
 Liquidity and Capital Resources
 53




---



##### Table of Contents



Operating Results
 2008
    
    
    2007
    
    
    2006(In millions, except volumes)Operating revenues
    
    $
    2,684
    
    
    $
    2,494
    
    
    $
    2,402Operating expenses
    
    
    (1,532
    )
    
    
    (1,383
    )
    
    
    (1,339
    )Operating income
    
    
    1,152
    
    
    
    1,111
    
    
    
    1,063Other income
    
    
    156
    
    
    
    157
    
    
    
    124EBIT before minority interests
    
    
    1,308
    
    
    
    1,268
    
    
    
    1,187Minority interests
    
    
    (35
    )
    
    
    (3
    )
    
    
    EBIT
    
    $
    1,273
    
    
    $
    1,265
    
    
    $
    1,187Throughput volumes (BBtu/d)(1)TGP
    
    
    4,864
    
    
    
    4,880
    
    
    
    4,534EPNG and MPC
    
    
    4,422
    
    
    
    4,216
    
    
    
    4,255CIG, WIC and CPG
    
    
    5,376
    
    
    
    4,906
    
    
    
    4,301SNG
    
    
    2,339
    
    
    
    2,345
    
    
    
    2,167Other
    
    
    50
    
    
    
    50
    
    
    
    50Equity investments(2)
    
    
    1,763
    
    
    
    1,734
    
    
    
    1,705Total throughput
    
    
    18,814
    
    
    
    18,131
    
    
    
    17,012
 
 (1)
    
    Volumes exclude intrasegment activities.(2)
    
    Represents our proportional share.  2008 to 2007
    
    
    2007 to 2006Variance
    
    
    VarianceRevenue
    
    
    Expense
    
    
    Other
    
    
    EBIT
    
    
    Revenue
    
    
    Expense
    
    
    Other
    
    
    EBITImpact
    
    
    Impact
    
    
    Impact
    
    
    Impact
    
    
    Impact
    
    
    Impact
    
    
    Impact
    
    
    ImpactFavorable/(Unfavorable)(In millions)Expansions
    
    $
    74
    
    
    $
    (26
    )
    
    $
    19
    
    
    $
    67
    
    
    $
    50
    
    
    $
    (7
    )
    
    $
    9
    
    
    $
    52Reservation and usage revenues
    
    
    67
    
    
    
    
    
    
    
    
    
    
    
    67
    
    
    
    31
    
    
    
    
    
    
    
    
    
    
    
    31Gas not used in operations
and revaluations
    
    
    33
    
    
    
    (13
    )
    
    
    
    
    
    
    20
    
    
    
    3
    
    
    
    (16
    )
    
    
    
    
    
    
    (13
    )Bankruptcy settlements
    
    
    27
    
    
    
    1
    
    
    
    
    
    
    
    28
    
    
    
    
    
    
    
    (3
    )
    
    
    
    
    
    
    (3
    )Operating and general and
administrative expense
    
    
    
    
    
    
    (62
    )
    
    
    
    
    
    
    (62
    )
    
    
    
    
    
    
    (35
    )
    
    
    
    
    
    
    (35
    )Gain/loss on long-lived assets
    
    
    
    
    
    
    (31
    )
    
    
    1
    
    
    
    (30
    )
    
    
    
    
    
    
    4
    
    
    
    (2
    )
    
    
    2Hurricanes
    
    
    (10
    )
    
    
    (14
    )
    
    
    
    
    
    
    (24
    )
    
    
    
    
    
    
    12
    
    
    
    
    
    
    
    12Equity earnings from Citrus
    
    
    
    
    
    
    
    
    
    
    (17
    )
    
    
    (17
    )
    
    
    
    
    
    
    
    
    
    
    19
    
    
    
    19Minority interests
    
    
    
    
    
    
    
    
    
    
    (32
    )
    
    
    (32
    )
    
    
    
    
    
    
    
    
    
    
    (3
    )
    
    
    (3
    )Other(1)
    
    
    (1
    )
    
    
    (4
    )
    
    
    (4
    )
    
    
    (9
    )
    
    
    8
    
    
    
    1
    
    
    
    7
    
    
    
    16Total impact on EBIT
    
    $
    190
    
    
    $
    (149
    )
    
    $
    (33
    )
    
    $
    8
    
    
    $
    92
    
    
    $
    (44
    )
    
    $
    30
    
    
    $
    78
 
 (1)
    
    Consists of individually insignificant items on several of our pipeline
systems. Expansions.
 54




---



##### Table of Contents



Reservation and Usage Revenues.
 
    
    increased demand for off-system and mainline capacity on our Rocky Mountain region
systems primarily due to lower natural gas prices in the Rocky Mountains as compared to
other regions in the United States;
    
    additional firm capacity sold in the northern and southern regions of our TGP system,
partially offset by lower surcharges from certain firm customers on this system ;
    
    increased reservation and usage revenues on our EPNG system due to higher amounts
charged on recontracted capacity in Arizona and California; and
    
    additional interruptible and firm commodity services provided in several of our pipeline
systems.
  
    
    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 of our TGP system; and
    
    increased rates on our CIG system effective October 2006 as a result of CIGs rate
settlement.
 Gas Not Used in Operations and Revaluations.
  Bankruptcy Settlements.
 Operating and General and Administrative Expenses.
 Gain/Loss on Long-Lived Assets.
 55




---



##### Table of Contents



Hurricanes. Liquidity and Capital Resources
 Equity Earnings from Citrus
 Minority Interests.
 Other Regulatory Matters.
   56




---



##### Table of Contents



Exploration and Production Segment
 Overview and Strategy
       57




---



##### Table of Contents



Significant Operational Factors Affecting the Year Ended December 31, 2008
 Production.
 2008
    
    2007
    
    2006United StatesCentral
    
    
    238
    
    
    
    227
    
    
    
    213Western
    
    
    154
    
    
    
    147
    
    
    
    132Texas Gulf Coast
    
    
    225
    
    
    
    213
    
    
    
    187Gulf of Mexico and south Louisiana
    
    
    114
    
    
    
    191
    
    
    
    174InternationalBrazil
    
    
    11
    
    
    
    14
    
    
    
    24Total Consolidated
    
    
    742
    
    
    
    792
    
    
    
    730Four Star
    
    
    74
    
    
    
    70
    
    
    
    68
 Central region
 Western region
 Texas Gulf Coast region
 Gulf of Mexico and south Louisiana region
 Brazil
 Four Star
 2008 Drilling Results
 Central.
 Western.
 Texas Gulf Coast.
 Gulf of Mexico and south Louisiana.
 Brazil.
 Egypt.
  58




---



##### Table of Contents



Cash Operating Costs.
  Reserve Replacement Ratio/Reserve Replacement Costs.
 Reserve replacement ratio
    
    Sum of reserve additions(1)Actual production for the corresponding periodReserve 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 for
prices and performance, 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. We have presented
these metrics separately, both including and excluding the
impact of price revisions on reserves, to demonstrate the effectiveness of our drilling program exclusive
of economic factors (such as price) outside of our control. All 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.   59




---



##### Table of Contents



Including Price Revisions
    
    Excluding Price Revisions2008
    
    2007
    
    2006
    
    2008
    
    2007
    
    2006($/Mcfe)
    
    
    
    
    
    
    
    
    
    ($/Mcfe)DomesticReserve replacement costs, including acquisitions
    
    $
    6.68
    
    
    $
    3.26
    
    
    $
    3.92
    
    
    $
    2.87
    
    
    $
    3.46
    
    
    $
    3.27Reserve replacement costs, excluding acquisitions
    
    
    7.01
    
    
    
    3.22
    
    
    
    3.94
    
    
    
    2.87
    
    
    
    3.65
    
    
    
    3.29WorldwideReserve replacement costs, including acquisitions
    
    $
    36.00
    
    
    $
    3.55
    
    
    $
    4.17
    
    
    $
    3.25
    
    
    $
    3.77
    
    
    $
    3.50Reserve replacement costs, excluding acquisitions
    
    
    56.05
    
    
    
    3.79
    
    
    
    4.19
    
    
    
    3.26
    
    
    
    4.29
    
    
    
    3.51
 (% of Production)
    
    (% of Production)DomesticReserve
replacement ratio, including acquisitions
    
    
    84
    %
    
    
    255
    %
    
    
    109
    %
    
    
    195
    %
    
    
    240
    %
    
    
    130
    %Reserve
replacement ratio, excluding acquisitions
    
    
    77
    %
    
    
    129
    %
    
    
    108
    %
    
    
    188
    %
    
    
    114
    %
    
    
    129
    %WorldwideReserve
replacement ratio, including acquisitions
    
    
    17
    %
    
    
    252
    %
    
    
    108
    %
    
    
    192
    %
    
    
    237
    %
    
    
    128
    %Reserve
replacement ratio, excluding acquisitions
    
    
    11
    %
    
    
    129
    %
    
    
    107
    %
    
    
    186
    %
    
    
    114
    %
    
    
    127
    %
  Including Price
    
    Excluding PriceRevisions
    
    RevisionsThree Years Ending December 31, 2008($/Mcfe)DomesticReserve replacement costs, including acquisitions
    
    $
    4.03
    
    
    $
    3.22Reserve replacement costs, excluding acquisitions
    
    
    4.37
    
    
    
    3.21WorldwideReserve replacement costs, including acquisitions
    
    $
    5.16
    
    
    $
    3.54Reserve replacement costs, excluding acquisitions
    
    
    6.20
    
    
    
    3.62
 Capital Expenditures.
 2008
    
    
    2007
    
    
    2006(in millions)Total oil and gas capital costs(1)
    
    $
    1,699
    
    
    $
    2,589
    
    
    $
    1,193Less: acquisition capital
    
    
    (51
    )
    
    
    (1,178
    )
    
    
    (4
    )Capital expenditures, excluding acquisitions
    
    $
    1,648
    
    
    $
    1,411
    
    
    $
    1,189
 
 (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. 60




---



##### Table of Contents



Outlook for 2009
   
    
    Capital expenditures, excluding acquisitions, of $0.9 billion to $1.3 billion. Of this
total, we expect to spend $0.7 billion to $1.0 billion on our domestic program and
approximately $250 million in Brazil and Egypt. Brazil capital includes the anticipated
costs to complete development of our Camarupim project in 2009.
    
    Average daily production volumes for the year of approximately 663 MMcfe/d to 747
MMcfe/d, which does not include approximately 62 MMcfe/d to 68 MMcfe/d from our equity
investment in Four Star. Production volumes from our Brazil operations are expected to
increase from an average of about 11 MMcfe/d in 2008 to between 45 MMcfe/d and 55 MMcfe/d
in 2009, with production volumes from the Camarupim Field expected to commence in the
second quarter of 2009.
    
    Average cash operating costs which include production costs, general and administrative
expenses and other expenses of approximately $2.05/Mcfe to $2.35/Mcfe for the year; and
    
    Depreciation, depletion and amortization rate of between $2.30/Mcfe and $2.50/Mcfe.
 Price Risk Management Activities
   Fixed PriceSwaps(1)
    
    Floors(1)
    
    Ceilings(1)
    
    Basis Swaps(1)(2)Texas Gulf Coast
    
    Western-Raton
    
    RockiesAverage
    
    
    
    
    
    Average
    
    
    
    
    
    AverageVolumes
    
    Price
    
    Volumes
    
    Price
    
    Volumes
    
    Price
    
    Volumes
    
    Avg. Price
    
    Volumes
    
    Avg. Price
    
    Volumes
    
    Avg. PriceNatural Gas2009
    
    
    8
    
    
    $
    7.33
    
    
    
    168
    
    
    $
    9.10
    
    
    
    143
    
    
    $
    15.41
    
    
    
    40
    
    
    $
    (0.33
    )
    
    
    25
    
    
    $
    (0.95
    )
    
    
    13
    
    
    $
    (2.01
    )2010
    
    
    5
    
    
    $
    3.70
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2011-2012
    
    
    7
    
    
    $
    3.88
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Oil2009
    
    
    3,431
    
    
    $
    109.93
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
 
 (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.  61




---



##### Table of Contents



Operating Results and Variance Analysis
  2008
    
    
    2007
    
    
    2006(In millions)Operating Revenues:Natural gas
    
    $
    1,885
    
    
    $
    1,764
    
    
    $
    1,406Oil, condensate and NGL
    
    
    507
    
    
    
    494
    
    
    
    430Changes in fair value of derivative
contracts not designated as accounting
hedges
    
    
    305
    
    
    
    7
    
    
    
    (40
    )Other
    
    
    65
    
    
    
    35
    
    
    
    58Total operating revenues
    
    
    2,762
    
    
    
    2,300
    
    
    
    1,854Operating Expenses:Cost of products
    
    
    (38
    )
    
    
    (20
    )
    
    
    (29
    )Transportation costs
    
    
    (79
    )
    
    
    (72
    )
    
    
    (58
    )Production costs
    
    
    (363
    )
    
    
    (344
    )
    
    
    (331
    )Depreciation, depletion and amortization
    
    
    (799
    )
    
    
    (780
    )
    
    
    (645
    )General and administrative expenses
    
    
    (160
    )
    
    
    (185
    )
    
    
    (156
    )Ceiling test charges
    
    
    (2,669
    )
    
    
    
    
    
    
    Other
    
    
    (12
    )
    
    
    (13
    )
    
    
    (10
    )Total operating expenses
    
    
    (4,120
    )
    
    
    (1,414
    )
    
    
    (1,229
    )Operating income
    
    
    (1,358
    )
    
    
    886
    
    
    
    625Other income (expense)(1)
    
    
    (90
    )
    
    
    23
    
    
    
    15EBIT
    
    $
    (1,448
    )
    
    $
    909
    
    
    $
    640
 
 (1)
    
    Other income includes equity earnings from our investment in Four Star, which
in 2008 included a $125 million impairment charge related to our ownership interest in Four
Star. 62




---



##### Table of Contents



Percent
    
    
    
    
    
    
    Percent2008
    
    
    Variance
    
    
    2007
    
    
    Variance
    
    
    2006Consolidated volumes, prices and costs per unit:Natural gasVolumes (MMcf)
    
    
    232,703
    
    
    
    (4
    )%
    
    
    242,316
    
    
    
    10
    %
    
    
    220,402Average realized prices including hedges($/Mcf)
    
    $
    8.10
    
    
    
    11
    %
    
    $
    7.28
    
    
    
    14
    %
    
    $
    6.38Average realized prices excluding hedges ($/Mcf)
    
    $
    8.43
    
    
    
    29
    %
    
    $
    6.53
    
    
    
    (2
    )%
    
    $
    6.64Average transportation costs ($/Mcf)
    
    $
    0.31
    
    
    
    15
    %
    
    $
    0.27
    
    
    
    17
    %
    
    $
    0.23Oil, condensate and NGLVolumes (MBbls)
    
    
    6,495
    
    
    
    (17
    )%
    
    
    7,821
    
    
    
    2
    %
    
    
    7,686Average realized prices including hedges ($/Bbl)
    
    $
    78.10
    
    
    
    24
    %
    
    $
    63.11
    
    
    
    13
    %
    
    $
    55.90Average realized prices excluding hedges ($/Bbl)
    
    $
    83.21
    
    
    
    31
    %
    
    $
    63.71
    
    
    
    13
    %
    
    $
    56.21Average transportation costs ($/Bbl)
    
    $
    0.96
    
    
    
    19
    %
    
    $
    0.81
    
    
    
    (1
    )%
    
    $
    0.82Total equivalent volumesMMcfe
    
    
    271,673
    
    
    
    (6
    )%
    
    
    289,242
    
    
    
    9
    %
    
    
    266,518MMcfe/d
    
    
    742
    
    
    
    (6
    )%
    
    
    792
    
    
    
    8
    %
    
    
    730Production costs and other cash operating costs ($/Mcfe)Average lease operating expenses
    
    $
    0.90
    
    
    
    2
    %
    
    $
    0.88
    
    
    
    (7
    )%
    
    $
    0.95Average production taxes(1)
    
    
    0.44
    
    
    
    42
    %
    
    
    0.31
    
    
    
    7
    %
    
    
    0.29Total production costs
    
    $
    1.34
    
    
    
    13
    %
    
    $
    1.19
    
    
    
    (4
    )%
    
    $
    1.24Average general and administrative expenses
    
    $
    0.59
    
    
    
    (8
    )%
    
    $
    0.64
    
    
    
    8
    %
    
    $
    0.59Average taxes, other than production and income taxes
    
    $
    0.04
    
    
    
    (20
    )%
    
    $
    0.05
    
    
    
    67
    %
    
    $
    0.03Total cash operating costs
    
    $
    1.97
    
    
    
    5
    %
    
    $
    1.88
    
    
    
    1
    %
    
    $
    1.86Depreciation, depletion and amortization ($/Mcfe)
    
    $
    2.94
    
    
    
    9
    %
    
    $
    2.70
    
    
    
    12
    %
    
    $
    2.42Unconsolidated affiliate volumes (Four Star)Natural gas (MMcf)
    
    
    20,576
    
    
    
    
    
    
    
    19,380
    
    
    
    
    
    
    
    18,140Oil, condensate and NGL (MBbls)
    
    
    1,054
    
    
    
    
    
    
    
    1,015
    
    
    
    
    
    
    
    1,087Total equivalent volumesMMcfe
    
    
    26,899
    
    
    
    
    
    
    
    25,470
    
    
    
    
    
    
    
    24,663MMcfe/d
    
    
    74
    
    
    
    
    
    
    
    70
    
    
    
    
    
    
    
    68
 
 (1)
    
    Production taxes include ad valorem and severance taxes. 63




---



##### Table of Contents



Year Ended December 31, 2008 Compared to Year Ended December 31, 2007
  VarianceOperating
    
    
    OperatingRevenue
    
    
    Expense
    
    
    Other
    
    
    EBITFavorable/(Unfavorable)(In millions)Natural Gas RevenuesHigher realized prices in 2008
    
    $
    441
    
    
    $
    
    
    
    $
    
    
    
    $
    441Impact of accounting hedges
    
    
    (257
    )
    
    
    
    
    
    
    
    
    
    
    (257
    )Lower volumes in 2008
    
    
    (63
    )
    
    
    
    
    
    
    
    
    
    
    (63
    )Oil, Condensate and NGL RevenuesHigher realized prices in 2008
    
    
    127
    
    
    
    
    
    
    
    
    
    
    
    127Impact of accounting hedges
    
    
    (29
    )
    
    
    
    
    
    
    
    
    
    
    (29
    )Lower volumes in 2008
    
    
    (85
    )
    
    
    
    
    
    
    
    
    
    
    (85
    )Other RevenueChange in fair value of derivatives not
designated as accounting hedges
    
    
    298
    
    
    
    
    
    
    
    
    
    
    
    298Other
    
    
    30
    
    
    
    
    
    
    
    
    
    
    
    30Depreciation, Depletion and Amortization ExpenseHigher depletion rate in 2008
    
    
    
    
    
    
    (64
    )
    
    
    
    
    
    
    (64
    )Lower production volumes in 2008
    
    
    
    
    
    
    45
    
    
    
    
    
    
    
    45Production CostsLower lease operating expenses in 2008
    
    
    
    
    
    
    10
    
    
    
    
    
    
    
    10Higher production taxes in 2008
    
    
    
    
    
    
    (29
    )
    
    
    
    
    
    
    (29
    )General and Administrative Expenses
    
    
    
    
    
    
    25
    
    
    
    
    
    
    
    25Ceiling Test Charges
    
    
    
    
    
    
    (2,669
    )
    
    
    
    
    
    
    (2,669
    )OtherEarnings from investment in Four Star
    
    
    
    
    
    
    
    
    
    
    (104
    )
    
    
    (104
    )Other
    
    
    
    
    
    
    (24
    )
    
    
    (9
    )
    
    
    (33
    )Total Variances
    
    $
    462
    
    
    $
    (2,706
    )
    
    $
    (113
    )
    
    $
    (2,357
    )
 Natural gas, oil, condensate and NGL revenues.
 Other revenue.
 64




---



##### Table of Contents



Depreciation, depletion and amortization expense.
 Production costs.
 General and administrative expenses.
 Ceiling test charges.
  Other.
 65




---



##### 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 RevenuesLower realized prices in 2007
    
    $
    (26
    )
    
    $
    
    
    
    $
    
    
    
    $
    (26
    )Impact of accounting hedges
    
    
    239
    
    
    
    
    
    
    
    
    
    
    
    239Higher volumes in 2007
    
    
    145
    
    
    
    
    
    
    
    
    
    
    
    145Oil, Condensate and NGL RevenuesHigher realized prices in 2007
    
    
    59
    
    
    
    
    
    
    
    
    
    
    
    59Impact of accounting 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 expenses 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
 Natural gas, oil, condensate and NGL revenues.
 Other revenue.
 Depreciation, depletion and amortization expense.
 Production costs.
 General and administrative expenses.
 66




---



##### Table of Contents



Marketing Segment
   Operating Results
 Overview.
 2008
    
    
    2007
    
    
    2006(In millions)Revenue by Significant Contract Type:Production-Related Natural Gas and Oil Derivative Contracts:Changes in fair value of options and swaps
    
    $
    (50
    )
    
    $
    (89
    )
    
    $
    269Contracts Related to Legacy Trading Operations:Changes in fair value of power contracts
    
    
    (46
    )
    
    
    (77
    )
    
    
    71Natural gas transportation-related contracts:Demand charges
    
    
    (35
    )
    
    
    (98
    )
    
    
    (125
    )Settlements, net of termination payments
    
    
    41
    
    
    
    76
    
    
    
    (110
    )Changes in fair value of other natural gas derivative contracts
    
    
    7
    
    
    
    (31
    )
    
    
    (163
    )Total revenues
    
    
    (83
    )
    
    
    (219
    )
    
    
    (58
    )Operating expenses
    
    
    (20
    )
    
    
    (15
    )
    
    
    (33
    )Operating loss
    
    
    (103
    )
    
    
    (234
    )
    
    
    (91
    )Other income, net
    
    
    (1
    )
    
    
    32
    
    
    
    20EBIT
    
    $
    (104
    )
    
    $
    (202
    )
    
    $
    (71
    )
   67




---



##### Table of Contents



Production-related Natural Gas and Oil Derivative Contracts
  Contracts Related to Legacy Trading Operations
 Power contracts.
  Natural gas transportation-related contracts.
 2008
    
    2007
    
    2006Alliance(1):Demand charges
    
    $
    
    
    
    $
    56
    
    
    $
    64Recovery
    
    
    
    
    
    
    48
    %
    
    
    59
    %Other:Demand charges
    
    $
    35
    
    
    $
    42
    
    
    $
    61Recovery
    
    
    100
    %
    
    
    100
    %
    
    
    68
    %
 
 (1)
    
    Effective November 2007, our obligation under the Alliance capacity
agreement was transferred to a third party. Excluded from amounts recovered is the $188
million we paid in 2006 in conjunction with the sale of this contract. 68




---



##### Table of Contents



Other natural gas derivative contracts.
 Power Segment
 Overview.
 Area
    
    Amount(In millions)BrazilPorto Velho
    
    $
    178Manaus & Rio Negro
    
    
    42Pipeline projects
    
    
    158Asia
    
    
    18Total
    
    $
    396
    2008
    
    
    2007
    
    
    2006(In millions)EBIT by Area:BrazilImpairments
    
    $
    
    
    
    $
    (72
    )
    
    $
    Other EBIT from operations
    
    
    7
    
    
    
    51
    
    
    
    64Other International PowerImpairments, net of gains (losses) on sales
    
    
    6
    
    
    
    (1
    )
    
    
    (12
    )Other EBIT from operations
    
    
    (2
    )
    
    
    (1
    )
    
    
    (1
    )Gain on sale of available-for-sale investment(1)
    
    
    
    
    
    
    
    
    
    
    47Other(2)
    
    
    (10
    )
    
    
    (14
    )
    
    
    (16
    )EBIT
    
    $
    1
    
    
    $
    (37
    )
    
    $
    82
 
 (1)
    
    Relates to the disposition of our remaining shares of International
Commodity Exchange in 2006.(2)
    
    Consists of indirect expenses and general and administrative costs. Brazil.
 69




---



##### Table of Contents



International Power.
 Corporate and Other Expenses, Net
  2008
    
    
    2007
    
    
    2006(In millions)Change in litigation, insurance and other reserves
    
    $
    84
    
    
    $
    23
    
    
    $
    (71
    )Early extinguishment/exchange of debt
    
    
    
    
    
    
    (291
    )
    
    
    (26
    )Foreign currency fluctuations on Euro-denominated debt
    
    
    
    
    
    
    (8
    )
    
    
    (20
    )Gain on the sale of assets
    
    
    35
    
    
    
    
    
    
    
    Other
    
    
    5
    
    
    
    (7
    )
    
    
    29Total EBIT
    
    $
    124
    
    
    $
    (283
    )
    
    $
    (88
    )
 Litigation, Insurance, and Other Reserves.
   Extinguishment of Debt.
 Interest and Debt Expense
  70




---



##### Table of Contents



Income Taxes
 Years Ended December 31,2008
    
    2007
    
    2006(In millions)Income taxes from continuing operations
    
    $
    (245
    )
    
    $
    222
    
    
    $
    (9
    )Effective tax rate
    
    
    23
    %
    
    
    34
    %
    
    
    (2
    )%
  Discontinued Operations
  Commitments and Contingencies
  71




---



##### Table of Contents



Liquidity and Capital Resources
   Available Liquidity and Liquidity Outlook for 2009.
  Total(In billions)PipelinesMaintenance
    
    $
    0.4Growth
    
    
    1.3Exploration and Production(1)
    
    
    1.3Other
    
    
    0.1$
    3.1
 
 (1)
    
    For 2009, our planned cash capital, excluding acquisitions, may range
from $0.9 billion to $1.3 billion.   72




---



##### Table of Contents



Additional Factors That Could Impact Our Future Liquidity.
 Price Risk Management Activities and Margining Requirements.
 Fixed Price
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    BasisSwaps(1)
    
    Floors(1)
    
    Ceilings(1)
    
    Swaps(1)(2)Average
    
    
    
    
    
    Average
    
    
    
    
    
    Average
    
    Texas Gulf Coast
    
    Western-Raton
    
    RockiesVolumes
    
    Price
    
    Volumes
    
    Price
    
    Volumes
    
    Price
    
    Volumes
    
    Avg. Price
    
    Volumes
    
    Avg. Price
    
    Volumes
    
    Avg. PriceNatural Gas2009
    
    
    8
    
    
    $
    7.33
    
    
    
    168
    
    
    $
    9.10
    
    
    
    143
    
    
    $
    15.41
    
    
    
    40
    
    
    $
    (0.33
    )
    
    
    25
    
    
    $
    (0.95
    )
    
    
    13
    
    
    $
    (2.01
    )2010
    
    
    5
    
    
    $
    3.70
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2011-2012
    
    
    7
    
    
    $
    3.88
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Oil2009
    
    
    3,431
    
    
    $
    109.93
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
 
 (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.    73




---



##### Table of Contents



Hurricanes Ike and Gustav.
 Overview of Cash Flow Activities.
 2008
    
    
    2007(In billions)Cash Flow from OperationsContinuing operating activitiesIncome (loss) from continuing operations
    
    $
    (0.8
    )
    
    $
    0.4Ceiling test charges
    
    
    2.7
    
    
    
    Other income adjustments
    
    
    1.2
    
    
    
    1.7Change in other assets and liabilities
    
    
    (0.7
    )
    
    
    (0.3
    )Total cash flow from operations
    
    $
    2.4
    
    
    $
    1.8Other Cash InflowsContinuing investing activitiesNet proceeds from the sale of assets and investments
    
    $
    0.7
    
    
    $
    0.1Other
    
    
    0.1
    
    
    
    0.8
    
    
    
    0.1Continuing financing activitiesNet proceeds from the issuance of long-term debt(1)
    
    
    4.6
    
    
    
    6.6Net proceeds from issuance of minority interest in consolidated subsidiary
    
    
    
    
    
    
    0.5Contributions from discontinued operations
    
    
    
    
    
    
    3.44.6
    
    
    
    10.5Total other cash inflows
    
    $
    5.4
    
    
    $
    10.6Cash OutflowsContinuing investing activitiesCapital expenditures
    
    $
    2.8
    
    
    $
    2.5Cash paid for acquisitions
    
    
    0.4
    
    
    
    1.23.2
    
    
    
    3.7Continuing financing activitiesPayments to retire long-term debt and other financing obligations(1)
    
    
    3.7
    
    
    
    8.9Dividends, repurchase of El Paso common stock and other
    
    
    0.2
    
    
    
    0.13.9
    
    
    
    9.0Total cash outflows
    
    $
    7.1
    
    
    $
    12.7Net change in cash
    
    $
    0.7
    
    
    $
    (0.3
    )
 
 (1)
    
    Includes activity under our revolving credit facilities. 74




---



##### Table of Contents



Off-Balance Sheet Arrangements
  Guarantees and Indemnifications
    Letters of Credit
  Interests in Variable Interest Entities
  75




---



##### Table of Contents



Contractual Obligations
  Due in Less
    
    
    Due in 1 to
    
    
    Due in 3 tothan 1 Year
    
    
    3 Years
    
    
    5 Years
    
    
    Thereafter
    
    
    Total(In millions)Long-term financing obligations:Principal
    
    $
    1,090
    
    
    $
    938
    
    
    $
    3,142
    
    
    $
    8,837
    
    
    $
    14,007Interest
    
    
    915
    
    
    
    1,708
    
    
    
    1,479
    
    
    
    7,540
    
    
    
    11,642Liabilities from
commodity-based derivative
contracts
    
    
    245
    
    
    
    430
    
    
    
    199
    
    
    
    122
    
    
    
    996Other contractual liabilities
    
    
    63
    
    
    
    76
    
    
    
    30
    
    
    
    43
    
    
    
    212Operating leases
    
    
    15
    
    
    
    18
    
    
    
    13
    
    
    
    24
    
    
    
    70Other contractual commitments
and purchase obligations:Transportation and storage
    
    
    39
    
    
    
    67
    
    
    
    42
    
    
    
    147
    
    
    
    295Other
    
    
    1,141
    
    
    
    986
    
    
    
    14
    
    
    
    9
    
    
    
    2,150Total contractual obligations
    
    $
    3,508
    
    
    $
    4,223
    
    
    $
    4,919
    
    
    $
    16,722
    
    
    $
    29,372
 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.
 76




---



##### Table of Contents




    
    Other Commitments.Included in these amounts are commitments for purchasing pipe and
related assets in our pipeline operations, 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.
 Commodity-Based Derivative Contracts.
 Maturity
    
    
    Maturity
    
    
    Maturity
    
    
    Maturity
    
    
    TotalLess Than
    
    
    1 to 3
    
    
    4 to 5
    
    
    6 to 10
    
    
    Fair1 Year
    
    
    Years
    
    
    Years
    
    
    Years
    
    
    Value(In millions)Assets
    
    $
    782
    
    
    
    148
    
    
    
    25
    
    
    
    16
    
    
    $
    971Liabilities
    
    
    (245
    )
    
    
    (430
    )
    
    
    (199
    )
    
    
    (122
    )
    
    
    (996
    )Total commodity-based derivatives
    
    $
    537
    
    
    
    (282
    )
    
    
    (174
    )
    
    
    (106
    )
    
    $
    (25
    )
  Other
    
    
    TotalDerivatives
    
    
    Commodity-
    
    
    Commodity-Designated
    
    
    Based
    
    
    Basedas Accounting Hedges
    
    
    Derivatives
    
    
    Derivatives(In millions)Fair 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
    
    
    
    18Net option premiums paid
    
    
    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
    )Fair value of contracts settled
    
    
    88
    
    
    
    257
    
    
    
    345Changes in fair value of contracts
    
    
    309
    
    
    
    197
    
    
    
    506Reclassification of de-designated hedges
    
    
    (395
    )
    
    
    395
    
    
    
    Net option premiums paid (received)
    
    
    21
    
    
    
    (5
    )
    
    
    16Net change in contracts outstanding during the period
    
    
    23
    
    
    
    844
    
    
    
    867Fair value of contracts outstanding at December 31, 2008
    
    $
    
    
    
    $
    (25
    )
    
    $
    (25
    )
 
 (1)
    
    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. Fair Value of Contract Settlements.
 Changes in Fair Value of Contracts.
 Reclassifications of De-designated Hedges.
 77




---



##### Table of Contents



Critical Accounting Estimates
  Accounting for Natural Gas and Oil Producing Activities.
    78




---



##### Table of Contents



Cost-Based Regulation Accounting for the Effects of Certain
Types of Regulation
 Accounting for Legal and Environmental Reserves, Guarantees and Indemnifications.
  79




---



##### Table of Contents



Off Balance Sheet Arrangements
 Accounting for Pension and Other Postretirement Benefits.
  Pension Benefits
    
    Other Postretirement BenefitsChange in Funded
    
    
    
    
    
    Change in FundedStatus and Pretax
    
    
    
    
    
    Status and PretaxAccumulated Other
    
    
    
    
    
    Accumulated OtherNet Benefit
    
    Comprehensive
    
    Net Benefit
    
    ComprehensiveExpense (Income)
    
    Income
    
    Expense (Income)
    
    IncomeOne percent increase in:Discount rates
    
    $
    (10
    )
    
    $
    146
    
    
    $
    
    
    
    $
    50Expected return on plan assets
    
    
    (23
    )
    
    
    
    
    
    
    (3
    )
    
    
    Rate of compensation increase
    
    
    1
    
    
    
    (5
    )
    
    
    
    
    
    
    Health care cost trends
    
    
    
    
    
    
    
    
    
    
    3
    
    
    
    (48
    )One percent decrease in:Discount rates
    
    $
    11
    
    
    $
    (170
    )
    
    $
    (1
    )
    
    $
    (54
    )Expected return on plan assets(1)
    
    
    23
    
    
    
    
    
    
    
    3
    
    
    
    Rate of compensation increase
    
    
    (1
    )
    
    
    4
    
    
    
    
    
    
    
    Health care cost trends
    
    
    
    
    
    
    
    
    
    
    (4
    )
    
    
    44
 
 (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.
  80




---



##### Table of Contents



Price Risk Management Activities.
  10 Percent Increase
    
    
    10 Percent DecreaseFair Value
    
    
    Fair Value
    
    
    Change
    
    
    Fair Value
    
    
    Change(In millions)Production-related derivatives
    
    $
    682
    
    
    $
    582
    
    
    $
    (100
    )
    
    $
    785
    
    
    $
    103Other commodity-based derivatives
    
    
    (707
    )
    
    
    (719
    )
    
    
    (12
    )
    
    
    (695
    )
    
    
    12Total
    
    $
    (25
    )
    
    $
    (137
    )
    
    $
    (112
    )
    
    $
    90
    
    
    $
    115
  Change in Discount Rate1 Percent Increase
    
    
    1 Percent DecreaseFair Value
    
    
    Fair Value
    
    
    Change
    
    
    Fair Value
    
    
    Change(In millions)Production-related derivatives
    
    $
    682
    
    
    $
    680
    
    
    $
    (2
    )
    
    $
    684
    
    
    $
    2Other commodity-based derivatives
    
    
    (707
    )
    
    
    (689
    )
    
    
    18
    
    
    
    (726
    )
    
    
    (19
    )Total
    
    $
    (25
    )
    
    $
    (9
    )
    
    $
    16
    
    
    $
    (42
    )
    
    $
    (17
    )
  Deferred Taxes and Uncertain Income Tax Positions.
 81




---



##### Table of Contents



Valuation Allowance.
 Uncertain Tax Positions.
 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.
 82




---



##### Table of Contents



ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
  
    
    Commodity Price Risk
 
    
    Changes in natural gas and oil prices impact the sale of natural gas and oil in
our Exploration and Production segment, affect gas not used in the operations of our
Pipelines segment and affect the fair value of our natural gas and oil derivative
contracts held in our Exploration & Production and Marketing segments;
    
    Changes in natural gas locational price differences affect our ability to
optimize pipeline transportation capacity contracts held in our Marketing segment; and
    
    Changes in electricity prices and locational price differences affect 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.
  83




---



##### Table of Contents



Commodity Price Risk
 Production-Related Derivatives
  Other Commodity-Based Derivatives
  Sensitivity Analysis
  Change in Market Price10 Percent Increase
    
    10 Percent DecreaseFair Value
    
    Fair Value
    
    Change
    
    Fair Value
    
    Change(In millions)Production-related
derivatives  net
assets
(liabilities)December 31, 2008
    
    $
    682
    
    
    $
    582
    
    
    $
    (100
    )
    
    $
    785
    
    
    $
    103December 31, 2007
    
    $
    (64
    )
    
    $
    (181
    )
    
    $
    (117
    )
    
    $
    58
    
    
    $
    122Other
commodity-based
derivatives  net
assets
(liabilities)December 31, 2008
    
    $
    (707
    )
    
    $
    (719
    )
    
    $
    (12
    )
    
    $
    (695
    )
    
    $
    12December 31, 2007
    
    $
    (828
    )
    
    $
    (846
    )
    
    $
    (18
    )
    
    $
    (810
    )
    
    $
    18
 84




---



##### Table of Contents



Interest Rate Risk
  December 31, 2008
    
    December 31, 2007Expected Fiscal Year of Maturity of Carrying Amounts
    
    
    
    
    
    Fair
    
    Carrying
    
    Fair2009
    
    2010
    
    2011
    
    2012
    
    2013
    
    Thereafter
    
    Total
    
    Value
    
    Amounts
    
    Value(In millions)Long-term debt and
other obligations,
including current
portion  fixed
rate
    
    
    
    
    
    $
    1,076
    
    
    $
    239
    
    
    $
    663
    
    
    $
    459
    
    
    $
    538
    
    
    $
    8,653
    
    
    
    
    
    
    $
    11,628
    
    
    $
    9,438
    
    
    $
    10,945
    
    
    $
    11,244Average interest
rate
    
    
    
    
    
    
    6.3
    %
    
    
    8.3
    %
    
    
    7.5
    %
    
    
    8.0
    %
    
    
    14.6
    %
    
    
    7.4
    %Long-term debt and
other obligations,
including current
portion  variable
rate
    
    
    
    
    
    $
    14
    
    
    $
    15
    
    
    $
    16
    
    
    $
    2,072
    
    
    $
    18
    
    
    $
    145
    
    
    
    
    
    
    $
    2,280
    
    
    $
    1,789
    
    
    $
    1,869
    
    
    $
    1,869Average interest
rate
    
    
    
    
    
    
    5.9
    %
    
    
    5.9
    %
    
    
    5.9
    %
    
    
    4.1
    %
    
    
    5.9
    %
    
    
    5.9
    %
 Foreign Currency Exchange Rate Risk
   
 85




---



##### Table of Contents



ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 Index
  PageManagements Annual Report on Internal Control over Financial Reporting
    
    87Reports of Independent Registered Public Accounting Firms
    
    88Consolidated Statements of Income
    
    92Consolidated Balance Sheets
    
    93Consolidated Statements of Cash Flows
    
    95Consolidated Statements of Stockholders Equity
    
    96Consolidated Statements of Comprehensive Income
    
    97Notes to Consolidated Financial Statements
    
    981. Basis of Presentation and Significant Accounting Policies
    
    982. Acquisitions and Divestitures
    
    1043. Ceiling Test Charges
    
    1064. Other Income and Other Expenses
    
    1065. Income Taxes
    
    1066. Earnings Per Share
    
    1097. Fair Value of Financial Instruments
    
    1108. Price Risk Management Activities
    
    1129. Regulatory Assets and Liabilities
    
    11510. Other Assets and Liabilities
    
    11611. Property, Plant and Equipment
    
    11712. Debt, Other Financing Obligations and Credit Facilities
    
    11913. Commitments and Contingencies
    
    12314. Retirement Benefits
    
    12915. Stockholders Equity
    
    13316. Stock-Based Compensation
    
    13417. Business Segment Information
    
    13618. Investments in, Earnings from and Transactions with Unconsolidated Affiliates
    
    140Supplemental Financial InformationSupplemental Selected Quarterly Financial Information (Unaudited)
    
    144Supplemental Natural Gas and Oil Operations (Unaudited)
    
    145Financial Statement ScheduleSchedule II  Valuation and Qualifying Accounts
    
    152
 86




---



##### 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
 87




---



##### Table of Contents



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
    Employers Accounting for Defined Benefit Pension and Other Postretirement Plans  An Amendment of
FASB Statements No. 87, 88, 106, and 132(R), 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).
  /s/ Ernst & Young LLPHouston, TexasFebruary 26, 2009 
 88




---



##### Table of Contents



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
       /s/ Ernst & Young LLPHouston, Texas
February 26, 2009 89




---



##### Table of Contents



Report of Independent Registered Public Accounting Firm
    /s/ PricewaterhouseCoopers LLPHouston, Texas
February 20, 2009 90




---



##### Table of Contents



Report of Independent Registered Public Accounting Firm
    
 91




---



##### Table of Contents



EL PASO CORPORATION
 
 CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per common share amounts)
 Year Ended December 31,2008
    
    
    2007
    
    
    2006Operating revenuesPipelines
    
    $
    2,684
    
    
    $
    2,494
    
    
    $
    2,402Exploration and Production
    
    
    2,762
    
    
    
    2,300
    
    
    
    1,854Marketing
    
    
    (83
    )
    
    
    (219
    )
    
    
    (58
    )Power
    
    
    
    
    
    
    
    
    
    
    6Corporate and eliminations
    
    
    
    
    
    
    73
    
    
    
    775,363
    
    
    
    4,648
    
    
    
    4,281Operating expensesCost of products and services
    
    
    245
    
    
    
    245
    
    
    
    238Operation and maintenance
    
    
    1,190
    
    
    
    1,333
    
    
    
    1,337Ceiling test charges
    
    
    2,669
    
    
    
    
    
    
    
    Depreciation, depletion and amortization
    
    
    1,205
    
    
    
    1,176
    
    
    
    1,047Taxes, other than income taxes
    
    
    284
    
    
    
    249
    
    
    
    2325,593
    
    
    
    3,003
    
    
    
    2,854Operating income (loss)
    
    
    (230
    )
    
    
    1,645
    
    
    
    1,427Earnings from unconsolidated affiliates
    
    
    48
    
    
    
    101
    
    
    
    145Loss on debt extinguishment
    
    
    
    
    
    
    (291
    )
    
    
    (26
    )Other income
    
    
    94
    
    
    
    214
    
    
    
    245Other expenses
    
    
    (32
    )
    
    
    (11
    )
    
    
    (40
    )Minority interests
    
    
    (34
    )
    
    
    (6
    )
    
    
    (1
    )Interest and debt expense
    
    
    (914
    )
    
    
    (994
    )
    
    
    (1,228
    )Income (loss) before income taxes from continuing operations
    
    
    (1,068
    )
    
    
    658
    
    
    
    522Income tax expense (benefit)
    
    
    (245
    )
    
    
    222
    
    
    
    (9
    )Income (loss) from continuing operations
    
    
    (823
    )
    
    
    436
    
    
    
    531Discontinued operations, net of income taxes
    
    
    
    
    
    
    674
    
    
    
    (56
    )Net income (loss)
    
    
    (823
    )
    
    
    1,110
    
    
    
    475Preferred stock dividends
    
    
    37
    
    
    
    37
    
    
    
    37Net income (loss) available to common stockholders
    
    $
    (860
    )
    
    $
    1,073
    
    
    $
    438Basic earnings (loss) per common shareIncome (loss) from continuing operations
    
    $
    (1.24
    )
    
    $
    0.57
    
    
    $
    0.73Discontinued operations, net of income taxes
    
    
    
    
    
    
    0.97
    
    
    
    (0.08
    )Net income (loss) per common share
    
    $
    (1.24
    )
    
    $
    1.54
    
    
    $
    0.65Diluted earnings (loss) per common shareIncome (loss) from continuing operations
    
    $
    (1.24
    )
    
    $
    0.57
    
    
    $
    0.72Discontinued operations, net of income taxes
    
    
    
    
    
    
    0.96
    
    
    
    (0.08
    )Net income (loss) per common share
    
    $
    (1.24
    )
    
    $
    1.53
    
    
    $
    0.64
  92




---



##### Table of Contents



EL PASO CORPORATION
 
 CONSOLIDATED BALANCE SHEETS
(In millions, except share amounts)
 December 31,2008
    
    
    2007ASSETSCurrent assetsCash and cash equivalents
    
    $
    1,024
    
    
    $
    285Accounts and notes receivableCustomer, net of allowance of $9 in 2008 and $17 in 2007
    
    
    466
    
    
    
    468Affiliates
    
    
    133
    
    
    
    196Other
    
    
    217
    
    
    
    201Materials and supplies
    
    
    187
    
    
    
    131Assets from price risk management activities
    
    
    876
    
    
    
    113Deferred income taxes
    
    
    
    
    
    
    191Other
    
    
    148
    
    
    
    127Total current assets
    
    
    3,051
    
    
    
    1,712Property, plant and equipment, at costPipelines
    
    
    18,042
    
    
    
    16,750Natural gas and oil properties, at full cost
    
    
    20,009
    
    
    
    19,048Other
    
    
    342
    
    
    
    53038,393
    
    
    
    36,328Less accumulated depreciation, depletion and amortization
    
    
    20,535
    
    
    
    16,974Total property, plant and equipment, net
    
    
    17,858
    
    
    
    19,354Other assetsInvestments in unconsolidated affiliates
    
    
    1,703
    
    
    
    1,614Assets from price risk management activities
    
    
    201
    
    
    
    302Other
    
    
    855
    
    
    
    1,5972,759
    
    
    
    3,513Total assets
    
    $
    23,668
    
    
    $
    24,579
  93




---



##### Table of Contents



EL PASO CORPORATION
 CONSOLIDATED BALANCE SHEETS
(In millions, except share amounts)
 December 31,2008
    
    
    2007LIABILITIES AND STOCKHOLDERS EQUITYCurrent liabilitiesAccounts payableTrade
    
    $
    372
    
    
    $
    460Affiliates
    
    
    6
    
    
    
    5Other
    
    
    674
    
    
    
    502Short-term financing obligations, including current maturities
    
    
    1,090
    
    
    
    331Liabilities from price risk management activities
    
    
    250
    
    
    
    267Accrued interest
    
    
    192
    
    
    
    195Other
    
    
    659
    
    
    
    653Total current liabilities
    
    
    3,243
    
    
    
    2,413Long-term financing obligations, less current maturities
    
    
    12,818
    
    
    
    12,483OtherLiabilities from price risk management activities
    
    
    767
    
    
    
    931Deferred income taxes
    
    
    565
    
    
    
    1,157Other
    
    
    1,679
    
    
    
    1,7503,011
    
    
    
    3,838Commitments and contingencies (Note 13)Minority interests
    
    
    561
    
    
    
    565Stockholders 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
712,628,781 shares in 2008 and 709,192,605 shares in 2007
    
    
    2,138
    
    
    
    2,128Additional paid-in capital
    
    
    4,612
    
    
    
    4,699Accumulated deficit
    
    
    (2,653
    )
    
    
    (1,834
    )Accumulated other comprehensive loss
    
    
    (532
    )
    
    
    (272
    )Treasury stock (at cost); 14,061,474 shares in 2008 and 8,656,095 shares in 2007
    
    
    (280
    )
    
    
    (191
    )Total stockholders equity
    
    
    4,035
    
    
    
    5,280Total liabilities and stockholders equity
    
    $
    23,668
    
    
    $
    24,579
  94




---



##### Table of Contents



EL PASO CORPORATION
 
 CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
 Year Ended December 31,2008
    
    
    2007
    
    
    2006Cash flows from operating activitiesNet income (loss)
    
    $
    (823
    )
    
    $
    1,110
    
    
    $
    475Less income (loss) from discontinued operations, net of income taxes
    
    
    
    
    
    
    674
    
    
    
    (56
    )Net income (loss) from continuing operations
    
    
    (823
    )
    
    
    436
    
    
    
    531Adjustments to reconcile net income to net cash from operating activities
Depreciation, depletion and amortization
    
    
    1,205
    
    
    
    1,176
    
    
    
    1,047Ceiling test charges
    
    
    2,669
    
    
    
    
    
    
    
    Deferred income tax expense (benefit)
    
    
    (172
    )
    
    
    182
    
    
    
    (20
    )Earnings from unconsolidated affiliates, adjusted for cash distributions
    
    
    132
    
    
    
    88
    
    
    
    (6
    )Loss on debt extinguishment
    
    
    
    
    
    
    291
    
    
    
    26Other non-cash income items
    
    
    66
    
    
    
    (25
    )
    
    
    72Asset and liability changesAccounts and notes receivable
    
    
    129
    
    
    
    213
    
    
    
    344Change in price risk management activities, net
    
    
    (461
    )
    
    
    (69
    )
    
    
    (420
    )Accounts payable
    
    
    (88
    )
    
    
    (67
    )
    
    
    (382
    )Change in margin and other deposits
    
    
    24
    
    
    
    90
    
    
    
    911Other asset changes
    
    
    (32
    )
    
    
    (150
    )
    
    
    (179
    )Other liability changes
    
    
    (279
    )
    
    
    (327
    )
    
    
    (100
    )Cash provided by continuing activities
    
    
    2,370
    
    
    
    1,838
    
    
    
    1,824Cash provided by (used in) discontinued activities
    
    
    
    
    
    
    (33
    )
    
    
    279Net cash provided by operating activities
    
    
    2,370
    
    
    
    1,805
    
    
    
    2,103Cash flows from investing activitiesCapital expenditures
    
    
    (2,757
    )
    
    
    (2,495
    )
    
    
    (2,164
    )Cash paid for acquisitions, net of cash acquired
    
    
    (362
    )
    
    
    (1,197
    )
    
    
    Net proceeds from the sale of assets and investments
    
    
    682
    
    
    
    106
    
    
    
    673Net change in restricted cash
    
    
    39
    
    
    
    33
    
    
    
    129Other
    
    
    50
    
    
    
    3
    
    
    
    23Cash used in continuing activities
    
    
    (2,348
    )
    
    
    (3,550
    )
    
    
    (1,339
    )Cash provided by discontinued activities
    
    
    
    
    
    
    3,660
    
    
    
    185Net cash provided by (used in) investing activities
    
    
    (2,348
    )
    
    
    110
    
    
    
    (1,154
    )Cash flows from financing activitiesNet proceeds from issuance of long-term debt
    
    
    4,641
    
    
    
    6,624
    
    
    
    375Payments to retire long-term debt and other financing obligations
    
    
    (3,679
    )
    
    
    (8,902
    )
    
    
    (3,024
    )Net proceeds from issuance of subsidiary equity
    
    
    15
    
    
    
    538
    
    
    
    Net proceeds from the issuance of common stock
    
    
    
    
    
    
    
    
    
    
    500Dividends paid
    
    
    (157
    )
    
    
    (149
    )
    
    
    (145
    )Payments to minority interest holders
    
    
    (29
    )
    
    
    
    
    
    
    (5
    )Repurchase of shares
    
    
    (77
    )
    
    
    
    
    
    
    Contributions from discontinued operations
    
    
    
    
    
    
    3,344
    
    
    
    232Other
    
    
    3
    
    
    
    5
    
    
    
    (13
    )Cash provided by (used in) continuing activities
    
    
    717
    
    
    
    1,460
    
    
    
    (2,080
    )Cash used in discontinued activities
    
    
    
    
    
    
    (3,627
    )
    
    
    (464
    )Net cash provided by (used in) financing activities
    
    
    717
    
    
    
    (2,167
    )
    
    
    (2,544
    )Change in cash and cash equivalents
    
    
    739
    
    
    
    (252
    )
    
    
    (1,595
    )Cash and cash equivalentsBeginning of period
    
    
    285
    
    
    
    537
    
    
    
    2,132End of period
    
    $
    1,024
    
    
    $
    285
    
    
    $
    537Supplemental cash flow information related to continuing operations
Interest paid, net of amounts capitalized
    
    $
    914
    
    
    $
    1,054
    
    
    $
    1,217Income tax payments
    
    
    12
    
    
    
    34
    
    
    
    77
  95




---



##### Table of Contents



EL PASO CORPORATION
 
 CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
(In millions)
 Year Ended December 31,2008
    
    
    2007
    
    
    2006Shares
    
    
    Amount
    
    
    Shares
    
    
    Amount
    
    
    Shares
    
    
    AmountPreferred stock, $0.01 par value:Balance at beginning and end of year
    
    
    1
    
    
    $
    750
    
    
    
    1
    
    
    $
    750
    
    
    
    1
    
    
    $
    750Common stock, $3.00 par value:Balance at beginning of year
    
    
    709
    
    
    
    2,128
    
    
    
    706
    
    
    
    2,118
    
    
    
    667
    
    
    
    2,001Equity offering
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    36
    
    
    
    107Other, net
    
    
    3
    
    
    
    10
    
    
    
    3
    
    
    
    10
    
    
    
    3
    
    
    
    10Balance at end of year
    
    
    712
    
    
    
    2,138
    
    
    
    709
    
    
    
    2,128
    
    
    
    706
    
    
    
    2,118Additional paid-in capital:Balance at beginning of year
    
    
    
    
    
    
    4,699
    
    
    
    
    
    
    
    4,804
    
    
    
    
    
    
    
    4,592Equity offering
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    393Dividends
    
    
    
    
    
    
    (163
    )
    
    
    
    
    
    
    (149
    )
    
    
    
    
    
    
    (147
    )Other, including stock-based compensation
    
    
    
    
    
    
    76
    
    
    
    
    
    
    
    44
    
    
    
    
    
    
    
    (34
    )Balance at end of year
    
    
    
    
    
    
    4,612
    
    
    
    
    
    
    
    4,699
    
    
    
    
    
    
    
    4,804Accumulated deficit:Balance at beginning of year
    
    
    
    
    
    
    (1,834
    )
    
    
    
    
    
    
    (2,940
    )
    
    
    
    
    
    
    (3,415
    )Net income (loss)
    
    
    
    
    
    
    (823
    )
    
    
    
    
    
    
    1,110
    
    
    
    
    
    
    
    475Cumulative effect of adopting of FIN No. 48
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (4
    )
    
    
    
    
    
    
    Cumulative effect of adopting SFAS No.
158, net of income tax of $2
    
    
    
    
    
    
    4
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Balance at end of year
    
    
    
    
    
    
    (2,653
    )
    
    
    
    
    
    
    (1,834
    )
    
    
    
    
    
    
    (2,940
    )Accumulated other comprehensive income (loss):Balance at beginning of year
    
    
    
    
    
    
    (272
    )
    
    
    
    
    
    
    (343
    )
    
    
    
    
    
    
    (332
    )Other comprehensive income (loss)
    
    
    
    
    
    
    (263
    )
    
    
    
    
    
    
    80
    
    
    
    
    
    
    
    380Cumulative effect of adopting SFAS No.
158, net of income tax of $2 in 2008, $4
in 2007 and $210 in 2006
    
    
    
    
    
    
    3
    
    
    
    
    
    
    
    (9
    )
    
    
    
    
    
    
    (391
    )Balance at end of year
    
    
    
    
    
    
    (532
    )
    
    
    
    
    
    
    (272
    )
    
    
    
    
    
    
    (343
    )Treasury stock, at cost:Balance at beginning of year
    
    
    (9
    )
    
    
    (191
    )
    
    
    (9
    )
    
    
    (203
    )
    
    
    (8
    )
    
    
    (190
    )Share repurchases
    
    
    (5
    )
    
    
    (77
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Stock-based and other compensation
    
    
    
    
    
    
    (12
    )
    
    
    
    
    
    
    12
    
    
    
    (1
    )
    
    
    (13
    )Balance at end of year
    
    
    (14
    )
    
    
    (280
    )
    
    
    (9
    )
    
    
    (191
    )
    
    
    (9
    )
    
    
    (203
    )Unamortized compensation:Balance at beginning of year
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (17
    )Adoption of SFAS No. 123(R)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    17Balance at end of year
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Total stockholders equity
    
    
    
    
    
    $
    4,035
    
    
    
    
    
    
    $
    5,280
    
    
    
    
    
    
    $
    4,186
  96




---



##### Table of Contents



EL PASO CORPORATION
 
 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In millions)
 Year Ended December 31,2008
    
    
    2007
    
    
    2006Net income (loss)
    
    $
    (823
    )
    
    $
    1,110
    
    
    $
    475Pension and postretirement obligations:Unrealized actuarial gains (losses)
arising during period (net of
income taxes of $288 in 2008, $91
in 2007 and $3 in 2006)
    
    
    (527
    )
    
    
    181
    
    
    
    5Reclassifications of actuarial
gains and losses during period (net
of income taxes of $8 in 2008 and
$13 in 2007)
    
    
    16
    
    
    
    26
    
    
    
    Cash flow hedging activities:Unrealized mark-to-market gains
(losses) arising during period (net
of income taxes of $106 in 2008, $2
in 2007 and $196 in 2006)
    
    
    191
    
    
    
    (3
    )
    
    
    352Reclassification adjustments for
changes in initial value to the
settlement date (net of income
taxes of $31 in 2008, $65 in 2007
and $15 in 2006)
    
    
    57
    
    
    
    (112
    )
    
    
    22Investments available for sale:Unrealized gains on investments
available for sale arising during
period (net of income taxes of $2
in 2007 and $16 in 2006)
    
    
    
    
    
    
    3
    
    
    
    28Realized gains on investments
available for sale arising during
period (net of income taxes of $8 in 2007 and $17 in 2006)
    
    
    
    
    
    
    (15
    )
    
    
    (31
    )Other
    
    
    
    
    
    
    
    
    
    
    4Other comprehensive income (loss)
    
    
    (263
    )
    
    
    80
    
    
    
    380Comprehensive income (loss)
    
    $
    (1,086
    )
    
    $
    1,190
    
    
    $
    855
  97




---



##### 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
  98




---



##### Table of Contents



Property, Plant and Equipment
 Pipelines and Other (Excluding Natural Gas and Oil Properties).
   Natural Gas and Oil Properties.
    99




---



##### Table of Contents



Asset and Investment Divestitures/Impairments
   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) .
  100




---



##### Table of Contents



Revenue Recognition
  Pipelines revenues.
 Exploration and Production revenues.
 Marketing revenues. Price Risk Management
Activities
 Environmental Costs and Other Contingencies
 Environmental Costs.
  101




---



##### Table of Contents



Other Contingencies.
 Price Risk Management Activities
     Income Taxes
  Accounting for Uncertainty in Income Taxes  an
interpretation of FASB Statement No. 109 Accounting for Income
Taxes,
 102




---



##### Table of Contents



Accounting for Asset Retirement Obligations
 Accounting
for Asset Retirement Obligations Accounting for Conditional Asset Retirement
Obligations
 Accounting for Stock-Based Compensation.
  New Accounting Pronouncements Issued But Not Yet Adopted
  Fair Value Measurements. Fair Value
Measurements
 Issuers Accounting
for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement,
 Business Combinations. Business
Combinations
 Noncontrolling Interests. Noncontrolling
Interests in Consolidated Financial Statements,
 103




---



##### Table of Contents



Oil and Gas Reserves Reporting.
 
 2. Acquisitions and Divestitures
 Acquisitions
 Gulf LNG.
 Exploration and Production properties.
 Divestitures
  2008
    
    
    2007
    
    
    2006(In millions)Exploration and Production
    
    $
    637
    
    
    $
    2
    
    
    $
    122Power
    
    
    16
    
    
    
    1
    
    
    
    531Marketing
    
    
    
    
    
    
    24
    
    
    
    Pipelines
    
    
    2
    
    
    
    36
    
    
    
    3Corporate
    
    
    20
    
    
    
    3
    
    
    
    2Total continuing(1)
    
    
    675
    
    
    
    66
    
    
    
    658Discontinued
    
    
    
    
    
    
    3,660
    
    
    
    368Total
    
    $
    675
    
    
    $
    3,726
    
    
    $
    1,026
 
 (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 $7 million, $40 million and
$15 million for the years ended December 31, 2008, 2007 and 2006. Exploration
and Production.
 Power.
 Marketing, Pipelines and Corporate.
 104




---



##### Table of Contents



Discontinued Operations and Assets Held for Sale
 Accounting for the Impairment or Disposal of Long-Lived Assets
 ANR and Related Operations.
 International Power Operations.
 Income Taxes on Discontinued Operations.
  ANR and
    
    
    InternationalRelated
    
    
    PowerOperations
    
    
    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
    )
 
 (1)
    
    Includes a loss of approximately $19 million associated with the extinguishment
of certain debt obligations. 105




---



##### Table of Contents



3. Ceiling Test Charges
  
 4. Other Income and Other Expenses
  2008
    
    
    2007
    
    
    2006(In millions)Other IncomeInterest income
    
    $
    19
    
    
    $
    49
    
    
    $
    138Allowance for funds used during construction
    
    
    37
    
    
    
    32
    
    
    
    20Deferred taxes on capitalized funds used during construction
    
    
    17
    
    
    
    18
    
    
    
    11Reversal of liability for legacy crude oil purchases (see Note 13)
    
    
    
    
    
    
    77
    
    
    
    Gain on sale of non-equity method investments
    
    
    
    
    
    
    24
    
    
    
    47Other
    
    
    21
    
    
    
    14
    
    
    
    29Total
    
    $
    94
    
    
    $
    214
    
    
    $
    245Other ExpensesForeign currency losses
    
    $
    28
    
    
    $
    1
    
    
    $
    20Loss on sale of non-equity method investments
    
    
    
    
    
    
    
    
    
    
    12Other
    
    
    4
    
    
    
    10
    
    
    
    8Total
    
    $
    32
    
    
    $
    11
    
    
    $
    40
 
 5. Income Taxes
 Pretax Income (Loss) and Income Tax Expense (Benefit).
 2008
    
    
    2007
    
    
    2006(In millions)Pretax Income (Loss)U.S
    
    $
    (603
    )
    
    $
    587
    
    
    $
    442Foreign
    
    
    (465
    )
    
    
    71
    
    
    
    80$
    (1,068
    )
    
    $
    658
    
    
    $
    522Components of Income Tax Expense (Benefit)CurrentFederal
    
    $
    (36
    )
    
    $
    (1
    )
    
    $
    7State
    
    
    (38
    )
    
    
    33
    
    
    
    (15
    )Foreign
    
    
    1
    
    
    
    8
    
    
    
    19(73
    )
    
    
    40
    
    
    
    11DeferredFederal
    
    
    (238
    )
    
    
    217
    
    
    
    (46
    )State
    
    
    27
    
    
    
    (39
    )
    
    
    32Foreign
    
    
    39
    
    
    
    4
    
    
    
    (6
    )(172
    )
    
    
    182
    
    
    
    (20
    )Total income tax expense (benefit)
    
    $
    (245
    )
    
    $
    222
    
    
    $
    (9
    )
 106




---



##### Table of Contents



Effective Tax Rate Reconciliation.
 2008
    
    
    2007
    
    
    2006(In millions, except rates)Income taxes at the statutory federal rate of 35%
    
    $
    (374
    )
    
    $
    230
    
    
    $
    183Increase (decrease)Audit settlements
    
    
    2
    
    
    
    
    
    
    
    (159
    )Earnings from unconsolidated affiliates where we
anticipate receiving dividends
    
    
    (41
    )
    
    
    (40
    )
    
    
    (35
    )Texas margins tax credit on accumulated net operating loss
    
    
    
    
    
    
    (16
    )
    
    
    State income taxes, net of federal income tax effect
    
    
    (6
    )
    
    
    14
    
    
    
    20Sales and write-offs of foreign investments
    
    
    (50
    )
    
    
    1
    
    
    
    (17
    )Foreign income (loss) taxed at different rates
    
    
    23
    
    
    
    24
    
    
    
    (13
    )Valuation allowances
    
    
    202
    
    
    
    10
    
    
    
    23Other
    
    
    (1
    )
    
    
    (1
    )
    
    
    (11
    )Income taxes
    
    $
    (245
    )
    
    $
    222
    
    
    $
    (9
    )Effective tax rate
    
    
    23
    %
    
    
    34
    %
    
    
    (2
    )%
 Foreign income (loss) taxed at different
rates Valuation allowances
 Deferred Tax Assets and Liabilities.
 2008
    
    
    2007(In millions)Deferred tax liabilitiesProperty, plant and equipment
    
    $
    2,775
    
    
    $
    3,106Investments in affiliates
    
    
    178
    
    
    
    227Benefits and compensation
    
    
    
    
    
    
    58Regulatory and other assets
    
    
    63
    
    
    
    49Total deferred tax liability
    
    
    3,016
    
    
    
    3,440Deferred tax assetsNet operating loss and tax credit carryoversFederal
    
    
    1,315
    
    
    
    1,135State
    
    
    178
    
    
    
    188Foreign
    
    
    147
    
    
    
    105Benefits and compensation
    
    
    356
    
    
    
    Price risk management activities
    
    
    112
    
    
    
    439Legal and other reserves
    
    
    205
    
    
    
    321Other
    
    
    465
    
    
    
    464Valuation allowance
    
    
    (337
    )
    
    
    (137
    )Total deferred tax asset
    
    
    2,441
    
    
    
    2,515Net deferred tax liability
    
    $
    575
    
    
    $
    925
  107




---



##### Table of Contents



Unrecognized Tax Benefits (Liabilities) for Uncertain Tax Matters (FIN No. 48).
  2008
    
    
    2007(In millions)Balance at January 1
    
    $
    157
    
    
    $
    139Additions:Tax positions taken in prior years
    
    
    24
    
    
    
    2Tax positions taken in current year
    
    
    32
    
    
    
    23Foreign currency fluctuations
    
    
    
    
    
    
    1Reductions:Tax positions taken in prior years
    
    
    (23
    )
    
    
    (5
    )Settlements with taxing authorities
    
    
    (11
    )
    
    
    (3
    )Statute of limitations expiration
    
    
    (5
    )
    
    
    Foreign currency fluctuations
    
    
    (1
    )
    
    
    Balance at December 31
    
    $
    173
    
    
    $
    157
   Tax Credit and NOL Carryovers.
 Carryover Period2009
    
    2010-2013
    
    2014-2018
    
    2019-2028
    
    Total(In millions)U.S. federal net operating loss
    
    $
    1
    
    
    $
    18
    
    
    $
    19
    
    
    $
    2,964
    
    
    $
    3,002     ]State net operating loss
    
    
    349
    
    
    
    577
    
    
    
    714
    
    
    
    1,120
    
    
    
    2,760
  108




---



##### Table of Contents



Valuation Allowances.
  
 6. Earnings Per Share
  2008
    
    
    2007
    
    
    2006Basic
    
    
    Diluted
    
    
    Basic
    
    
    Diluted
    
    
    Basic
    
    
    Diluted(In millions, except per share amounts)Income (loss) from continuing operations
    
    $
    (823
    )
    
    $
    (823
    )
    
    $
    436
    
    
    $
    436
    
    
    $
    531
    
    
    $
    531Convertible preferred stock dividends
    
    
    (37
    )
    
    
    (37
    )
    
    
    (37
    )
    
    
    (37
    )
    
    
    (37
    )
    
    
    Income (loss) from continuing operations
available to common stockholders
    
    
    (860
    )
    
    
    (860
    )
    
    
    399
    
    
    
    399
    
    
    
    494
    
    
    
    531Discontinued operations, net of income taxes
    
    
    
    
    
    
    
    
    
    
    674
    
    
    
    674
    
    
    
    (56
    )
    
    
    (56
    )Net income (loss) available to common
stockholders
    
    $
    (860
    )
    
    $
    (860
    )
    
    $
    1,073
    
    
    $
    1,073
    
    
    $
    438
    
    
    $
    475Weighted average common shares outstanding
    
    
    696
    
    
    
    696
    
    
    
    696
    
    
    
    696
    
    
    
    678
    
    
    
    678Effect of dilutive securities:Options and restricted stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3
    
    
    
    
    
    
    
    4Convertible preferred stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    57Weighted average common shares outstanding
and dilutive potential common shares
    
    
    696
    
    
    
    696
    
    
    
    696
    
    
    
    699
    
    
    
    678
    
    
    
    739Earnings per common share:Income (loss) from continuing operations
    
    $
    (1.24
    )
    
    $
    (1.24
    )
    
    $
    0.57
    
    
    $
    0.57
    
    
    $
    0.73
    
    
    $
    0.72Discontinued operations, net of income taxes
    
    
    
    
    
    
    
    
    
    
    0.97
    
    
    
    0.96
    
    
    
    (0.08
    )
    
    
    (0.08
    )Net income (loss)
    
    $
    (1.24
    )
    
    $
    (1.24
    )
    
    $
    1.54
    
    
    $
    1.53
    
    
    $
    0.65
    
    
    $
    0.64
  109




---



##### Table of Contents



7. Fair Value of Financial Instruments
 Fair Value Measurements The Fair Value Option for Financial Assets and Financial Liabilities
  
    
    Level 1 instruments fair values are based on quoted prices for the instruments in
actively traded markets. Included in this level are our marketable securities invested in
non-qualified compensation plans whose fair value is determined using the quoted prices of
these instruments.
    
    Level 2 instruments fair values are primarily based on pricing data representative of
quoted prices for similar assets and liabilities in active markets (or identical assets and
liabilities in less active markets). Included in this level are our foreign currency and
interest rate swaps. Also included in this level are our production-related natural gas
and oil derivatives and certain of our other natural gas derivatives (such as natural gas
supply arrangements) whose fair values are based on commodity pricing data obtained from
third party pricing sources and our creditworthiness or that of our counterparties
(adjusted for collateral related to those positions).
    
    Level 3 instruments fair values are partially calculated using pricing data that is
similar to Level 2 above, but their fair value also reflects adjustments for being in less
liquid markets or having longer contractual terms. For these instruments, we obtain pricing
data from third party pricing sources, adjust this data based on the liquidity of the
underlying forward markets over the contractual terms and use the adjusted pricing data to
develop an estimate of forward price curves that market participants would use. The curves
are then used to estimate the value of settlements in future periods based on contractual
settlement quantities and dates. Our valuation of these instruments considers specific
contractual terms, statistical and simulation analysis, present value concepts and other
internal assumptions related to (i) contract maturities that extend beyond the periods in
which quoted market prices are available; (ii) the uniqueness of the contract terms; (iii)
the limited availability of forward pricing information in markets where there is a lack
of viable participants, such as in the PJM forward power market and the forward market for
ammonia; and (iv) our creditworthiness or that of our counterparties (adjusted for
collateral related to those positions). Since a significant portion of the fair value of
our power-related derivatives and certain of our remaining natural gas derivatives with
longer terms or in less liquid markets than similar Level 2 derivatives, rely on the
techniques discussed above, we classify these instruments as Level 3 instruments.
 110




---



##### Table of Contents



Level 1
    
    
    Level 2
    
    
    Level 3
    
    
    TotalAssetsCommodity-based derivativesProduction-related natural gas and oil derivatives
    
    $
    
    
    
    $
    727
    
    
    $
    
    
    
    $
    727Other natural gas derivatives
    
    
    
    
    
    
    141
    
    
    
    31
    
    
    
    172Power-related derivatives
    
    
    
    
    
    
    
    
    
    
    72
    
    
    
    72Foreign
currency derivatives
    
    
    
    
    
    
    106
    
    
    
    
    
    
    
    106Marketable securities invested in non-qualified compensation plans
    
    
    19
    
    
    
    
    
    
    
    
    
    
    
    19Total assets
    
    $
    19
    
    
    $
    974
    
    
    $
    103
    
    
    $
    1,096
 Level 1
    
    
    Level 2
    
    
    Level 3
    
    
    TotalLiabilitiesCommodity-based derivativesProduction-related natural gas and oil derivatives
    
    $
    
    
    
    $
    (45
    )
    
    $
    
    
    
    $
    (45
    )Other natural gas derivatives
    
    
    
    
    
    
    (255
    )
    
    
    (186
    )
    
    
    (441
    )Power-related derivatives
    
    
    
    
    
    
    
    
    
    
    (510
    )
    
    
    (510
    )Interest rate derivatives
    
    
    
    
    
    
    (21
    )
    
    
    
    
    
    
    (21
    )Other
    
    
    
    
    
    
    
    
    
    
    (55
    )
    
    
    (55
    )Total liabilities
    
    
    
    
    
    
    (321
    )
    
    
    (751
    )
    
    
    (1,072
    )Total
    
    $
    19
    
    
    $
    653
    
    
    $
    (648
    )
    
    $
    24
   Change in fairChange in fair
    
    
    Change in fair
    
    
    value reflected inBalance at
    
    
    value reflected in
    
    
    value reflected in
    
    
    long-termBeginning of
    
    
    operating
    
    
    operating
    
    
    financing
    
    
    
    
    
    
    Settlements,
    
    
    Balance at End ofPeriod
    
    
    revenues(1)
    
    
    expenses(2)
    
    
    obligations(3)
    
    
    Transfers(4)
    
    
    Net
    
    
    PeriodAssets
    
    $
    250
    
    
    $
    2
    
    
    $
    
    
    
    $
    (24
    )
    
    $
    (85
    )
    
    $
    (40
    )
    
    $
    103Liabilities
    
    
    (839
    )
    
    
    (57
    )
    
    
    (19
    )
    
    
    
    
    
    
    
    
    
    
    164
    
    
    
    (751
    )Total
    
    $
    (589
    )
    
    $
    (55
    )
    
    $
    (19
    )
    
    $
    (24
    )
    
    $
    (85
    )
    
    $
    124
    
    
    $
    (648
    )
 
 (1)
    
    Includes approximately $46 million of net losses that had not been realized
through settlements for the year ended December 31, 2008.(2)
    
    Includes approximately $19 million of net losses that had not been realized
through settlements for the year ended December 31, 2008.(3)
    
    Includes approximately $24 million of net losses that had not been realized through
settlements for the year ended December 31, 2008.(4)
    
    We transferred our foreign currency swaps and certain of our interest rate swaps out
of Level 3 based on additional information received about their fair values during 2008. 111




---



##### Table of Contents



As of December 31,2008
    
    2007Carrying
    
    Fair
    
    Carrying
    
    FairAmount
    
    Value
    
    Amount
    
    Value(In millions)Long-term financing obligations, including current maturities
    
    $
    13,908
    
    
    $
    11,227
    
    
    $
    12,814
    
    
    $
    13,113Marketable securities invested in non-qualified compensation plans
    
    
    19
    
    
    
    19
    
    
    
    20
    
    
    
    20Commodity-based derivatives
    
    
    (25
    )
    
    
    (25
    )
    
    
    (892
    )
    
    
    (892
    )Interest rate and foreign currency derivatives
    
    
    85
    
    
    
    85
    
    
    
    109
    
    
    
    109Other
    
    
    72
    
    
    
    72
    
    
    
    64
    
    
    
    64
  
 8. Price Risk Management Activities
  As of December 31,2008
    
    
    2007(In millions)Net assets (liabilities):Derivatives designated as accounting hedges
    
    $
    
    
    
    $
    (23
    )Derivatives not designated as accounting hedges
    
    
    (25
    )
    
    
    (869
    )Total commodity-based derivatives
    
    
    (25
    )
    
    
    (892
    )Interest rate and foreign currency derivatives
    
    
    85
    
    
    
    109Net liabilities from price risk management activities(1)
    
    $
    60
    
    
    $
    (783
    )
 
 (1)
    
    Included in both current and non-current assets and liabilities on the balance
sheet. Derivatives Designated as Hedges
  112




---



##### Table of Contents



Cash Flow Hedges.
 AccumulatedOther
    
    
    EstimatedComprehensive
    
    
    Income (Loss)
    
    
    FinalIncome (Loss)
    
    
    Reclassification
    
    
    Termination2008
    
    
    2007
    
    
    in 2009(1)
    
    
    Year(In millions)Commodity cash flow hedgesHeld by consolidated entities
    
    $
    
    
    
    $
    (25
    )
    
    $
    De-designated
    
    
    241
    
    
    
    
    
    
    
    260
    
    
    
    2012Total commodity cash flow hedges
    
    
    241
    
    
    
    (25
    )
    
    
    260Interest rate and foreign currency cash flow hedgesHeld by consolidated entities
    
    
    (12
    )
    
    
    (2
    )
    
    
    
    
    
    
    2015Held by unconsolidated affiliates
    
    
    (13
    )
    
    
    (4
    )
    
    
    
    
    
    
    2013De-designated
    
    
    (3
    )
    
    
    (4
    )
    
    
    
    
    
    
    2009Total interest rate and foreign currency cash flow hedges
    
    
    (28
    )
    
    
    (10
    )
    
    
    Total cash flow hedges
    
    $
    213
    
    
    $
    (35
    )
    
    $
    260
 
 (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
    
    
    2008
    
    
    2007
    
    
    2008
    
    
    2007Fixed-to-floating swaps
    
    LIBOR + 4.18%
    
    $
    218
    
    
    $
    218
    
    
    $
    12
    
    
    $
    (5
    )Fixed-to-floating cross currency swaps(2)
    
    LIBOR + 4.23%
    
    
    379
    
    
    
    379
    
    
    
    94
    
    
    
    118$
    106
    
    
    $
    113
 
 (1)
    
    We did not record any ineffectiveness related to our fair value hedges in 2008
or 2007.(2)
    
    As of December 31, 2008 and 2007, these derivatives, when combined with our
Euro denominated debt, converted 330 million Euro of our debt to $379 million. Credit Risk
  113




---



##### Table of Contents



Below
    
    
    NotCounterparty
    
    Investment Grade(1)
    
    
    Investment Grade(1)
    
    
    Rated(1)
    
    
    Total(In millions)December 31, 2008Energy marketers
    
    $
    247
    
    
    $
    72
    
    
    $
    
    
    
    $
    319Natural gas and electric utilities
    
    
    
    
    
    
    
    
    
    
    30
    
    
    
    30Financial institutions and other
    
    
    480
    
    
    
    
    
    
    
    3
    
    
    
    483Net financial instrument assets
    
    
    727
    
    
    
    72
    
    
    
    33
    
    
    
    832Collateral held by us
    
    
    
    
    
    
    (62
    )
    
    
    (30
    )
    
    
    (92
    )Net exposure from derivative assets
    
    $
    727
    
    
    $
    10
    
    
    $
    3
    
    
    $
    740
 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
 
 (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 does not meet the criteria of Investment
Grade. Not Rated includes counterparties that are not rated by any public rating
service.   114




---



##### Table of Contents



9. Regulatory Assets and Liabilities
  2008
    
    
    2007(In millions)Current regulatory assetsDeferred fuel loss and unaccounted for gas
    
    $
    31
    
    
    $
    Other
    
    
    8
    
    
    
    Total current regulatory assets
    
    
    39
    
    
    
    Non-current regulatory assetsTaxes on capitalized funds used during construction
    
    
    137
    
    
    
    122Postretirement benefits
    
    
    21
    
    
    
    18Unamortized net loss on reacquired debt
    
    
    72
    
    
    
    59Other
    
    
    22
    
    
    
    22Total non-current regulatory assets
    
    
    252
    
    
    
    221Total regulatory assets
    
    $
    291
    
    
    $
    221Current regulatory liabilitiesOver-collected fuel variance
    
    $
    46
    
    
    $
    19Other
    
    
    21
    
    
    
    22Total current regulatory liabilities
    
    
    67
    
    
    
    41Non-current regulatory liabilitiesEnvironmental liability
    
    
    157
    
    
    
    143Property and plant depreciation
    
    
    60
    
    
    
    74Postretirement benefits
    
    
    32
    
    
    
    90Plant regulatory liability
    
    
    11
    
    
    
    11Other
    
    
    3
    
    
    
    10Total non-current regulatory liabilities
    
    
    263
    
    
    
    328Total regulatory liabilities
    
    $
    330
    
    
    $
    369
 115




---



##### Table of Contents



10. Other Assets and Liabilities
  2008
    
    
    2007(In millions)Other current assetsPrepaid expenses
    
    $
    69
    
    
    $
    66Margin and other deposits held by others
    
    
    5
    
    
    
    27Regulatory assets (Note 9)
    
    
    39
    
    
    
    Other
    
    
    35
    
    
    
    34Total
    
    $
    148
    
    
    $
    127Other non-current assetsPension, other postretirement and postemployment benefits (Note 14)
    
    $
    45
    
    
    $
    660Notes receivable from affiliates
    
    
    240
    
    
    
    220Restricted cash (Note 1)
    
    
    57
    
    
    
    91Unamortized debt expenses
    
    
    112
    
    
    
    107Regulatory assets (Note 9)
    
    
    252
    
    
    
    221Long-term receivables
    
    
    50
    
    
    
    116Other
    
    
    99
    
    
    
    182Total
    
    $
    855
    
    
    $
    1,597
 2008
    
    
    2007(In millions)Other current liabilitiesAccrued taxes, other than income
    
    $
    83
    
    
    $
    89Income taxes
    
    
    4
    
    
    
    47Environmental, legal and rate reserves (Note 13)
    
    
    131
    
    
    
    174Deposits
    
    
    69
    
    
    
    62Pension and other postretirement benefits (Note 14)
    
    
    46
    
    
    
    28Asset retirement obligations (Note 11)
    
    
    83
    
    
    
    41Dividends payable
    
    
    44
    
    
    
    37Regulatory liabilities (Note 9)
    
    
    67
    
    
    
    41Other
    
    
    132
    
    
    
    134Total
    
    $
    659
    
    
    $
    653Other non-current liabilitiesEnvironmental and legal reserves (Note 13)
    
    $
    161
    
    
    $
    590Pension, other postretirement and postemployment benefits (Note 14)
    
    
    686
    
    
    
    236Regulatory liabilities (Note 9)
    
    
    263
    
    
    
    328Asset retirement obligations (Note 11)
    
    
    171
    
    
    
    212Other deferred credits
    
    
    56
    
    
    
    62Insurance reserves
    
    
    84
    
    
    
    111Other
    
    
    258
    
    
    
    211Total
    
    $
    1,679
    
    
    $
    1,750
 116




---



##### Table of Contents



11.Property, Plant and Equipment
 Depreciable lives.
 DepreciableMethod
    
    
    
    Lives(In years)Regulated transmission systems
    
    Composite
    
    
    (1)Non-regulated assetsNatural gas and oil properties
    
    
    (2)
    
    
    
    (2)Transmission and storage facilities
    
    Straight-line
    
    
    15-25Gathering and processing systems
    
    Straight-line
    
    
    15-40Transportation equipment
    
    Straight-line
    
    
    5Buildings and improvements
    
    Straight-line
    
    
    3-48Office 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 or impaired. See Note 1 for additional information. Excess purchase costs.
 Capitalized costs during construction.
 Construction work-in progress.
 Asset retirement obligations.
 117




---



##### Table of Contents



2008
    
    
    2007(In millions)Net asset retirement liability at January 1
    
    $
    253
    
    
    $
    243Liabilities settled
    
    
    (120
    )
    
    
    (62
    )Accretion expense
    
    
    16
    
    
    
    23Liabilities incurred
    
    
    31
    
    
    
    16Changes in estimate
    
    
    74
    
    
    
    33Net asset retirement liability at December 31
    
    $
    254
    
    
    $
    253
 118




---



##### Table of Contents



12. Debt, Other Financing Obligations and Other Credit Facilities
 Year Ended December 31,2008
    
    
    2007(In millions)Short-term financing obligations, including current maturities
    
    $
    1,090
    
    
    $
    331Long-term financing obligations
    
    
    12,818
    
    
    
    12,483Total
    
    $
    13,908
    
    
    $
    12,814
  Year Ended December 31,2008
    
    
    2007(In millions)Colorado Interstate Gas Company (CIG)Notes and debentures, 5.95% through 6.85%, due 2015 through 2037
    
    $
    475
    
    
    $
    575El Paso CorporationNotes, 6.375% through 12%, due 2009 through 2037
    
    
    6,936
    
    
    
    6,090$1.5 billion revolver, variable due 2012
    
    
    522
    
    
    
    425El Paso Natural Gas Company (EPNG)Notes, 5.95% through 8.625%, due 2010 through 2032
    
    
    1,169
    
    
    
    1,169El Paso Exploration & Production Company (EPEP)Senior note, 7.75%, due 2013
    
    
    1
    
    
    
    1Revolving credit facility, variable due 2012
    
    
    914
    
    
    
    750El Paso Pipeline Partners, L.P. (EPB)Revolving credit facility, variable due 2012
    
    
    585
    
    
    
    455Notes, 7.76% through 8.00%, due 2011 through 2013
    
    
    140
    
    
    
    Notes, variable due 2012
    
    
    35
    
    
    
    Southern Natural Gas Company (SNG)Notes, 5.9% through 8.0%, due 2017 through 2032
    
    
    911
    
    
    
    1,134Tennessee Gas Pipeline Company(TGP)Notes, 6.0% through 8.375%, due 2011 through 2037
    
    
    1,626
    
    
    
    1,626Other
    
    
    252
    
    
    
    28913,566
    
    
    
    12,514Other financing obligationsCapital Trust I, due 2028
    
    
    325
    
    
    
    325Other
    
    
    116
    
    
    
    8Subtotal
    
    
    14,007
    
    
    
    12,847Less:Other, including unamortized discounts and premiums
    
    
    99
    
    
    
    33Current maturities
    
    
    1,090
    
    
    
    331Total long-term financing obligations, less current maturities
    
    $
    12,818
    
    
    $
    12,483
 119




---



##### Table of Contents



Changes in Long-Term Financing Obligations.
 CashBook Value
    
    
    Received /Company
    
    Interest Rate
    
    
    Increase (Decrease)
    
    
    (Paid)(2)IssuancesEl PasoRevolving Credit Facilities
    
    variable
    
    
    $
    2,697
    
    
    $
    2,697Notes due 2018
    
    
    7.250
    %
    
    
    600
    
    
    
    595Notes due 2013(1)
    
    
    12.000
    %
    
    
    445
    
    
    
    438EPEP Revolving Credit Facility
    
    variable
    
    
    
    549
    
    
    
    549El Paso Pipeline Partners, L.P.Revolving Credit Facility
    
    variable
    
    
    
    188
    
    
    
    188Private Placement Notes
    
    various
    
    
    
    175
    
    
    
    174Increases through December 31, 2008
    
    
    
    
    
    $
    4,654
    
    
    $
    4,641Repayments, repurchases and otherEl PasoRevolving Credit Facilities
    
    variable
    
    
    $
    (2,600
    )
    
    $
    (2,600
    )Notes
    
    6.625% to 7.625%
    
    
    (258
    )
    
    
    (258
    )EPEP Revolving Credit Facility
    
    variable
    
    
    
    (385
    )
    
    
    (385
    )EPB Revolving Credit Facility
    
    variable
    
    
    
    (58
    )
    
    
    (58
    )CIG
    
    5.950% to 6.800%
    
    
    (100
    )
    
    
    (103
    )SNG
    
    6.125% to 8.000%
    
    
    (223
    )
    
    
    (236
    )Other
    
    various
    
    
    
    64
    
    
    
    (39
    )Decreases through December 31, 2008
    
    
    
    
    
    $
    (3,560
    )
    
    $
    (3,679
    )
 
 (1)
    
    Principal amount of the note is $500 million.(2)
    
    Amounts presented are net of associated underwriting discounts and expenses.  Debt Maturities.
 2009
    
    $
    1,090
    (1)2010
    
    
    2552011
    
    
    6832012
    
    
    2,5312013
    
    
    611Thereafter
    
    
    8,837Total long-term financing obligations, including current maturities
    
    $
    14,007
 
 (1)
    
    This amount does not include the fair value of our fixed-to-floating cross currency derivative assets of $94 million. Credit Facilities/Letters of Credit
  120




---



##### Table of Contents



$1.5 Billion Revolving Credit Agreement.
  Unsecured Revolving Credit Facility.
 Unsecured Credit Facilities.
  EPEP $1.0 Billion Revolving Credit Agreement.
 EPEP $300 Million Revolving Credit Agreement.
 EPBs $750 Million Revolving Credit Facility.
 121




---



##### Table of Contents



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 5.25 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 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 and $300 Million Revolving Credit Agreements.
 EPBs $750 Million Revolving Credit Facility.
 Other Restrictions and Provisions.
  122




---



##### Table of Contents



Other Financing Arrangements
 Capital Trusts.
  WYCO.
 Non-Recourse Project Financings.
 
 13. 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
 123




---



##### Table of Contents



Retiree Medical Benefits Matters. Yolton et al. v. El Paso
Tennessee Pipeline Co. and Case Corporation .
 Price Reporting Litigation. In re: Western States Wholesale Natural Gas
Antitrust Litigation Farmland Industries v. Oneok Inc., et al. Missouri Public Service Commission v. El Paso Corporation, et al. Leggett, et al. v. Duke Energy Corporation, et al. Ever-Bloom Inc., et al. v. AEP Energy Services
Inc., et al. Learjet, Inc., et al. v. Oneok Inc., et al. Breckenridge, et al. v. Oneok Inc., et al. Arandell, et al. v. Xcel Energy, et al. Heartland, et al. v. Oneok Inc., et al. Leggett Missouri Public Service Breckenridge Case Western States Ever-Bloom
 Gas Measurement Cases. In re: Natural Gas Royalties Qui
Tam Litigation,
 Will Price, et al. v.
Gas Pipelines and Their Predecessors, et al.,
 124




---



##### Table of Contents



MTBE
 Government Investigations and Inquiries
 Reserve Revisions.
  Rates and Regulatory Matters
 EPNG Rate Case.
 125




---



##### Table of Contents



Notice of Proposed Rulemaking.
 Other Matter
 Navajo Nation
 126




---



##### Table of Contents



Environmental Matters
   December 31, 2008Sites
    
    Expected
    
    
    High(In millions)Operating
    
    $
    17
    
    
    $
    23Non-operating
    
    
    168
    
    
    
    321Superfund
    
    
    19
    
    
    
    44Total
    
    $
    204
    
    
    $
    388
  Balance as of January 1, 2008
    
    $
    260Additions/adjustments for remediation activities
    
    
    (11
    )Payments for remediation activities
    
    
    (44
    )Other changes, net
    
    
    (1
    )Balance as of December 31, 2008
    
    $
    204
 CERCLA Matters.
  127




---



##### Table of Contents



Greenhouse
Gas (GHG) Emissions.
 Commitments, Purchase Obligations and Other Matters
 Operating Leases.
 OperatingYear Ending December 31,
    
    Leases(In millions)2009
    
    $
    152010
    
    
    102011
    
    
    82012
    
    
    72013
    
    
    6Thereafter
    
    
    24Total
    
    $
    70
  Guarantees and Indemnifications.
  128




---



##### Table of Contents



Purchase Obligations.
 Other Commercial Commitments.
 Navajo Nation
 
 14. Retirement Benefits
 Overview of Retirement Benefits
 Pension Benefits.
  Retirement Savings Plan.
 Other Postretirement Benefits.
 129




---



##### Table of Contents



Other Matters.
  Pension
and Other Postretirement Benefits
 .
  Benefit
Obligation,Plan Assets and Funded Status.
 December 31, 2008
    
    
    September 30, 2007Pension
    
    
    OPEB
    
    
    Pension
    
    
    OPEB(In millions)Change in benefit obligation:(1)Benefit obligation  beginning of period
    
    $
    2,027
    
    
    $
    418
    
    
    $
    2,157
    
    
    $
    494Service cost
    
    
    18
    
    
    
    
    
    
    
    17
    
    
    
    1Interest cost
    
    
    150
    
    
    
    44
    
    
    
    119
    
    
    
    26Participant contributions
    
    
    
    
    
    
    13
    
    
    
    
    
    
    
    32Actuarial gain
    
    
    (12
    )
    
    
    (12
    )
    
    
    (86
    )
    
    
    (66
    )Benefits paid(2)
    
    
    (209
    )
    
    
    (72
    )
    
    
    (186
    )
    
    
    (69
    )Case liability reclassification
    
    
    
    
    
    
    282
    
    
    
    
    
    
    
    Other
    
    
    15
    
    
    
    
    
    
    
    6
    
    
    
    Benefit obligation  end of period
    
    $
    1,989
    
    
    $
    673
    
    
    $
    2,027
    
    
    $
    418Change in plan assets:Fair value of plan assets  beginning of period
    
    $
    2,537
    
    
    $
    303
    
    
    $
    2,382
    
    
    $
    276Actual return on plan assets(3)
    
    
    (561
    )
    
    
    (67
    )
    
    
    333
    
    
    
    39Employer contributions
    
    
    6
    
    
    
    39
    
    
    
    8
    
    
    
    25Participant contributions
    
    
    
    
    
    
    13
    
    
    
    
    
    
    
    32Benefits paid
    
    
    (209
    )
    
    
    (78
    )
    
    
    (186
    )
    
    
    (69
    )Fair value of plan assets  end of period
    
    $
    1,773
    
    
    $
    210
    
    
    $
    2,537
    
    
    $
    303Reconciliation of funded status:Fair value of plan assets
    
    $
    1,773
    
    
    $
    210
    
    
    $
    2,537
    
    
    $
    303Less: Benefit obligation
    
    
    1,989
    
    
    
    673
    
    
    
    2,027
    
    
    
    418Fourth quarter contributions
    
    
    
    
    
    
    
    
    
    
    3
    
    
    
    5Net asset (liability) at December 31
    
    $
    (216
    )
    
    $
    (463
    )
    
    $
    513
    
    
    $
    (110
    )
 
 (1)
    
    The benefit obligation for our pension plans represents the projected benefit
obligation and the benefit obligation for our other postretirement benefit plans represents
the accumulated postretirement benefit obligation.(2)
    
    Amounts for other postretirement benefits are shown net of a subsidy related to
the Medicare Prescription Drug, Improvement, and Modernization Act of 2003.(3)
    
    We defer the difference between our actual return on plan assets and our
expected return over a three year period, after which they are considered for inclusion in net
benefit expense or income. Our deferred actuarial gains and losses are amortized only to the
extent that our remaining unrecognized actual gains and losses exceed the greater of 10
percent of our benefit obligations or market related value of plan assets. 130




---



##### Table of Contents



OtherPension Benefits
    
    Postretirement Benefits2008
    
    2007
    
    2008
    
    2007(In millions)Current benefit liability
    
    $
    4
    
    
    $
    4
    
    
    $
    42
    
    
    $
    24Non-current benefit liability
    
    
    212
    
    
    
    33
    
    
    
    463
    
    
    
    192Non-current benefit asset
    
    
    
    
    
    
    550
    
    
    
    42
    
    
    
    106Accumulated other
comprehensive income (loss),
net of income taxes
    
    
    (770
    )
    
    
    (269
    )
    
    
    25
    
    
    
    32
    131




---



##### Table of Contents



Plan Assets.
 Pension Plans
    
    Other Postretirement PlansAsset Category
    
    Target
    
    Actual 2008(1)
    
    Actual 2007
    
    Target
    
    Actual 2008
    
    Actual 2007(Percent)
    
    
    
    
    
    
    
    
    
    (Percent)Equity securities
    
    
    60
    
    
    
    48
    
    
    
    67
    
    
    
    65
    
    
    
    64
    
    
    
    63Debt securities
    
    
    40
    
    
    
    50
    
    
    
    32
    
    
    
    35
    
    
    
    34
    
    
    
    33Other
    
    
    
    
    
    
    2
    
    
    
    1
    
    
    
    
    
    
    
    2
    
    
    
    4Total
    
    
    100
    
    
    
    100
    
    
    
    100
    
    
    
    100
    
    
    
    100
    
    
    
    100
 
 (1)
    
    Actual allocations are different than target due to market declines discussed
above. Expected Payment of Future Benefits.
 OtherYear Ending
    
    
    
    
    
    PostretirementDecember 31,
    
    Pension Benefits
    
    Benefits(1)(In millions)2009
    
    $
    182
    
    
    $
    612010
    
    
    183
    
    
    
    612011
    
    
    179
    
    
    
    612012
    
    
    179
    
    
    
    602013
    
    
    181
    
    
    
    602014-2018
    
    
    874
    
    
    
    276
 
 (1)
    
    Includes a reduction in each of the years presented for participant
contributions and an expected subsidy related to the Medicare
Prescription Drug, Improvement,
and Modernization Act of 2003. Actuarial Assumptions and Sensitivity Analysis.
 Pension Benefits
    
    Other Postretirement Benefits2008
    
    2007
    
    2006
    
    2008
    
    2007
    
    2006(Percent)
    
    
    
    
    
    
    
    
    
    (Percent)Assumptions related to benefit obligations at
December 31, 2008 and September 30, 2007 and
2006 measurement dates:Discount rate
    
    
    6.33
    
    
    
    6.25
    
    
    
    5.75
    
    
    
    5.98
    
    
    
    6.05
    
    
    
    5.50Rate of compensation increase
    
    
    4.18
    
    
    
    4.27
    
    
    
    4.00Assumptions related to benefit costs for the
year ended December 31:Discount rate
    
    
    6.25
    
    
    
    5.75
    
    
    
    5.50
    
    
    
    6.05
    
    
    
    5.50
    
    
    
    5.25Expected return on plan assets(1)
    
    
    8.00
    
    
    
    8.00
    
    
    
    8.00
    
    
    
    8.00
    
    
    
    8.00
    
    
    
    8.00Rate of compensation increase
    
    
    4.27
    
    
    
    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. 132




---



##### Table of Contents



2008
    
    2007(In millions)One percentage point increase:Aggregate of service cost and interest cost
    
    $
    2
    
    
    $
    1Accumulated postretirement benefit obligation
    
    
    48
    
    
    
    13One percentage point decrease:
Aggregate of service cost and interest cost
    
    $
    (2
    )
    
    $
    (1
    )Accumulated postretirement benefit obligation
    
    
    (44
    )
    
    
    (12
    )
 Components of Net Benefit Cost (Income).
 Pension Benefits
    
    
    Other Postretirement Benefits2008
    
    
    2007
    
    
    2006
    
    
    2008
    
    
    2007
    
    
    2006(In millions)Service cost
    
    $
    15
    
    
    $
    17
    
    
    $
    17
    
    
    $
    
    
    
    $
    1
    
    
    $
    11Interest cost
    
    
    120
    
    
    
    119
    
    
    
    118
    
    
    
    38
    
    
    
    26
    
    
    
    26Expected return on plan assets
    
    
    (187
    )
    
    
    (181
    )
    
    
    (175
    )
    
    
    (17
    )
    
    
    (16
    )
    
    
    (14
    )Amortization of net actuarial (gain) loss
    
    
    24
    
    
    
    43
    
    
    
    55
    
    
    
    (5
    )
    
    
    (1
    )
    
    
    Amortization of prior service credit(1)
    
    
    (2
    )
    
    
    (2
    )
    
    
    (2
    )
    
    
    (1
    )
    
    
    (1
    )
    
    
    (1
    )Other
    
    
    
    
    
    
    
    
    
    
    (2
    )
    
    
    
    
    
    
    
    
    
    
    (1
    )Net benefit cost (income)
    
    $
    (30
    )
    
    $
    (4
    )
    
    $
    11
    
    
    $
    15
    
    
    $
    9
    
    
    $
    21
 
 (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, or in the case of retired participants, over the
average remaining life. 
 15. Stockholders Equity
 Share Repurchase Program.
 Convertible Perpetual Preferred Stock.
 133




---



##### Table of Contents



Common and Preferred Stock Dividends.
 ConvertibleCommon Stock
    
    Preferred StockAmount paid in 2008
    
    $
    120
    
    
    $
    37Amount paid in January 2009
    
    $
    34
    
    
    $
    9Declared in 2009:Date of declaration
    
    February 10, 2009
    
    February 10, 2009Payable to shareholders on record
    
    March 6, 2009
    
    March 15, 2009Date payable
    
    April 1, 2009
    
    April 1, 2009
   Accumulated Other Comprehensive Income.
 2008
    
    
    2007Cash flow hedges (see Note 8)
    
    $
    213
    
    
    $
    (35
    )Pension and other postretirement benefits (see Note 14)
    
    
    (745
    )
    
    
    (237
    )Total accumulated other comprehensive loss, net of income taxes
    
    $
    (532
    )
    
    $
    (272
    )
 
 16. Stock-Based Compensation
 Overview.
  134




---



##### Table of Contents



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, 2007
    
    
    23,983,995
    
    
    $
    31.93Granted
    
    
    5,082,009
    
    
    $
    16.64Exercised
    
    
    (1,107,406
    )
    
    $
    9.58Forfeited or canceled
    
    
    (465,005
    )
    
    $
    17.26Expired
    
    
    (2,723,320
    )
    
    $
    46.73Outstanding at December 31, 2008
    
    
    24,770,273
    
    
    $
    28.44
    
    
    
    5.46
    
    
    $
    1Vested at December 31, 2008 or
expected to vest in the future
    
    
    24,326,671
    
    
    $
    28.68
    
    
    
    5.40
    
    
    $
    1Exercisable at December 31, 2008
    
    
    15,898,229
    
    
    $
    35.75
    
    
    
    3.69
    
    
    $
    1
  Fair Value Assumptions.
  2008
    
    2007
    
    2006Expected Term in Years
    
    
    6.0
    
    
    
    6.0
    
    
    
    6.0Expected Volatility
    
    
    35
    %
    
    
    34
    %
    
    
    38
    %Expected Dividends
    
    
    1
    %
    
    
    1
    %
    
    
    1.3
    %Risk-Free Interest Rate
    
    
    2.8
    %
    
    
    4.6
    %
    
    
    4.9
    %
 Share Based Payment
 135




---



##### Table of Contents



Restricted Stock.
 Weighted AverageGrant Date Fair ValueNonvested Shares
    
    # Shares
    
    per ShareNonvested at December 31, 2007
    
    
    3,915,940
    
    
    $
    13.74Granted
    
    
    2,240,971
    
    
    $
    15.46Vested
    
    
    (1,844,599
    )
    
    $
    13.12Forfeited
    
    
    (213,970
    )
    
    $
    14.76Nonvested at December 31, 2008
    
    
    4,098,342
    
    
    $
    14.91
   Employee Stock Purchase Plan.
 
 17. Business Segment Information
  Pipelines.
 Exploration and Production.
 Marketing.
 Power.
  136




---



##### Table of Contents



2008
    
    
    2007
    
    
    2006(In millions)Segment EBIT
    
    $
    (278
    )
    
    $
    1,935
    
    
    $
    1,838Corporate and other
    
    
    124
    
    
    
    (283
    )
    
    
    (88
    )Interest and debt expense
    
    
    (914
    )
    
    
    (994
    )
    
    
    (1,228
    )Income taxes
    
    
    245
    
    
    
    (222
    )
    
    
    9Income (loss) from continuing operations
    
    $
    (823
    )
    
    $
    436
    
    
    $
    531
  As of or for the Year Ended December 31, 2008SegmentExploration and
    
    
    
    
    
    
    
    
    
    CorporatePipelines
    
    Production
    
    Marketing
    
    Power
    
    and Other(1)
    
    Total(In millions)Revenue from external customersDomestic
    
    $
    2,621
    
    
    $
    1,317
    (2)
    
    $
    1,137
    
    
    $
    
    
    
    $
    9
    
    
    $
    5,084Foreign
    
    
    11
    
    
    
    22
    (2)
    
    
    237
    
    
    
    
    
    
    
    9
    
    
    
    279Intersegment revenue
    
    
    52
    
    
    
    1,423
    (2)
    
    
    (1,457
    )
    
    
    
    
    
    
    (18
    )
    
    
    Operation and maintenance
    
    
    863
    
    
    
    404
    
    
    
    19
    
    
    
    15
    
    
    
    (111
    )
    
    
    1,190Ceiling test charges
    
    
    
    
    
    
    2,669
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2,669Depreciation, depletion and
amortization
    
    
    395
    
    
    
    799
    
    
    
    
    
    
    
    1
    
    
    
    10
    
    
    
    1,205Earnings from unconsolidated affiliates
    
    
    97
    
    
    
    (93
    )
    
    
    
    
    
    
    40
    
    
    
    4
    
    
    
    48EBIT
    
    
    1,273
    
    
    
    (1,448
    )
    
    
    (104
    )
    
    
    1
    
    
    
    124
    
    
    
    (154
    )Assets of continuing operationsDomestic
    
    
    14,917
    
    
    
    5,821
    
    
    
    444
    
    
    
    5
    
    
    
    1,489
    
    
    
    22,676Foreign(3)
    
    
    204
    
    
    
    321
    
    
    
    21
    
    
    
    412
    
    
    
    34
    
    
    
    992Capital expenditures and investments
in and advances to unconsolidated
affiliates, net(4)
    
    
    1,457
    
    
    
    1,622
    
    
    
    
    
    
    
    (16
    )
    
    
    43
    
    
    
    3,106Total investments in unconsolidated
affiliates
    
    
    1,054
    
    
    
    531
    
    
    
    
    
    
    
    99
    
    
    
    19
    
    
    
    1,703
 
 (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.(2)
    
    Revenues from external customers include gains and losses related to our price
risk management activities associated with our natural gas and oil production. Intersegment
revenues represent sales to our Marketing segment, which is responsible for marketing a
significant portion of our production to third parties.(3)
    
    Of total foreign assets, approximately $0.3 billion relates to property, plant
and equipment, and approximately $0.5 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. 137




---



##### Table of Contents



As of or for the Year Ended December 31, 2007SegmentsExploration and
    
    
    
    
    
    
    
    
    
    Corporate(1)Pipelines
    
    Production
    
    Marketing
    
    Power
    
    and Other
    
    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 price
risk management activities associated with our natural gas and oil production. Intersegment
revenues represent sales to our Marketing segment, which is responsible for marketing a
significant portion of our production to third parties.(3)
    
    Of total foreign assets, approximately $0.6 billion relates to property, plan
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. Also includes $77 million in other income related to the reversal of a
liability related to a legacy crude oil marketing and trading business matter. 138




---



##### 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 (losses) 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 price
risk management activities associated with our natural gas and oil production. Intersegment
revenues represent sales to our Marketing segment, which is responsible for marketing a
significant portion of our production to third parties.(3)
    
    Excludes assets of discontinued operations of $4,133 million.(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. 139




---



##### Table of Contents



18. Investments in, Earnings from and Transactions with Unconsolidated Affiliates
  Net Ownership
    
    
    
    
    
    
    
    
    
    
    Earnings (Losses) fromInterest
    
    
    Investment
    
    
    Unconsolidated Affiliates2008
    
    
    2007
    
    
    2008
    
    
    2007
    
    
    2008
    
    
    2007
    
    
    2006(Percent)
    
    
    (In millions)
    
    
    (In millions)Four Star(1)
    
    
    49
    
    
    
    49
    
    
    $
    525
    
    
    $
    698
    
    
    $
    (93
    )
    
    $
    12
    
    
    $
    10Citrus
    
    
    50
    
    
    
    50
    
    
    
    564
    
    
    
    576
    
    
    
    64
    
    
    
    81
    
    
    
    62Gulf LNG(2)
    
    
    50
    
    
    
    
    
    
    
    279
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Bolivia to Brazil Pipeline
    
    
    8
    
    
    
    8
    
    
    
    119
    
    
    
    105
    
    
    
    25
    
    
    
    11
    
    
    
    11Gasoductos de Chihuahua
    
    
    50
    
    
    
    50
    
    
    
    174
    
    
    
    146
    
    
    
    29
    
    
    
    21
    
    
    
    25Manaus/Rio Negro(3)
    
    
    
    
    
    
    100
    
    
    
    
    
    
    
    56
    
    
    
    
    
    
    
    (6
    )
    
    
    17Porto Velho(4)
    
    
    50
    
    
    
    50
    
    
    
    (64
    )
    
    
    (60
    )
    
    
    1
    
    
    
    (23
    )
    
    
    2Asian and Central American Investments(5)
    
    various
    
    various
    
    
    13
    
    
    
    26
    
    
    
    6
    
    
    
    (1
    )
    
    
    (6
    )Argentina to Chile Pipeline
    
    
    22
    
    
    
    22
    
    
    
    27
    
    
    
    21
    
    
    
    7
    
    
    
    6
    
    
    
    5Other
    
    various
    
    various
    
    
    66
    
    
    
    46
    
    
    
    9
    
    
    
    
    
    
    
    19Total
    
    
    
    
    
    
    
    
    
    $
    1,703
    
    
    $
    1,614
    
    
    $
    48
    
    
    $
    101
    
    
    $
    145
 
 (1)
    
    We recorded amortization of our purchase cost in excess of the underlying net assets
of Four Star of $53 million during each of the years ended December 31, 2008 and 2007 and $54
million for the year ended December 31, 2006.(2)
    
    In February 2008, we acquired a 50 percent interest in Gulf LNG. See Note 2.(3)
    
    We transferred ownership of these plants to the power purchaser in January
2008. Accordingly, we eliminated our equity investments in these entities and retained current
assets of $80 million and current liabilities of $24 million in January 2008. For a further
discussion, see Matters that Could Impact Our Investmentsbelow.(4)
    
    As of December 31, 2008 and 2007, we had outstanding advances and receivables
of $242 million and $335 million related to our investment
in Porto Velho, that are not included in the table above.
In February 2009, we completed the sale of our investment in and
receivables from Porto Velho.
For a further discussion, see Matters that Could Impact Our Investmentsbelow.(5)
    
    In the second quarter of 2008, we sold our interests in the Khulna and
Tipitapa power facilities.  140




---



##### Table of Contents



Investment or Group
    
    2008
    
    
    2007
    
    
    2006(In millions)Four Star
    
    $
    (125
    )
    
    $
    
    
    
    $
    Porto Velho(1)
    
    
    
    
    
    
    (32
    )
    
    
    Manaus and Rio Negro
    
    
    
    
    
    
    (15
    )
    
    
    Other
    
    
    7
    
    
    
    (3
    )
    
    
    6$
    (118
    )
    
    $
    (50
    )
    
    $
    6
 
 (1)
    
    Amount in 2007 does not include a $25 million impairment of our note
receivable.  Year Ended December 31,2008
    
    2007
    
    2006(In millions)Operating results data:Operating revenues
    
    $
    708
    
    
    $
    872
    
    
    $
    1,101Operating expenses
    
    
    331
    
    
    
    528
    
    
    
    741Income from continuing operations.
    
    
    220
    
    
    
    211
    
    
    
    174Net income (1)
    
    
    220
    
    
    
    211
    
    
    
    174Financial position data:(2)Current assets
    
    $
    320
    
    
    $
    390
    
    
    $
    441Non-current assets
    
    
    2,667
    
    
    
    2,323
    
    
    
    2,408Short-term debt
    
    
    141
    
    
    
    41
    
    
    
    82Other current liabilities
    
    
    789
    
    
    
    328
    
    
    
    321Long-term debt
    
    
    169
    
    
    
    519
    
    
    
    556Other non-current liabilities
    
    
    666
    
    
    
    588
    
    
    
    592Equity in net assets
    
    
    1,222
    
    
    
    1,237
    
    
    
    1,298
 
 (1)
    
    Includes net income (loss) of $1 million, $(1) million and $20 million in 2008,
2007 and 2006, related to our proportionate share of affiliates in which we hold greater than
a 50 percent interest.(2)
    
    Includes total assets of $6 million and $190 million as of December 31, 2008
and 2007 related to our proportionate share of affiliates in which we hold greater than a 50
percent interest.  2008
    
    2007
    
    2006(In millions)Operating revenue(1)
    
    $
    7
    
    
    $
    7
    
    
    $
    64Cost of sales
    
    
    
    
    
    
    5
    
    
    
    3Other income
    
    
    1
    
    
    
    4
    
    
    
    6Interest income(2)
    
    
    3
    
    
    
    1
    
    
    
    46Interest expense
    
    
    3
    
    
    
    
    
    
    
    
 
 (1)
    
    Decrease in 2007 primarily due to the sale of investments in our Power segment.(2)
    
    Decrease in 2007 primarily due to the impairment of our Porto Velho note
receivable in 2007. 141




---



##### Table of Contents



Accounts Receivable Sales Program. Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities .
 Matters that Could Impact Our Investments
  Porto Velho.
 Manaus /Rio Negro.
 142




---



##### Table of Contents



Investment in Bolivia.
 Investment in Argentina.
 143




---



##### 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)2008Operating revenues
    
    $
    1,269
    
    
    $
    1,153
    
    
    $
    1,598
    
    
    $
    1,343
    
    
    $
    5,363Operating income (loss)
    
    
    550
    
    
    
    421
    
    
    
    839
    
    
    
    (2,040
    )
    
    
    (230
    )Earnings (losses) from unconsolidated
Affiliates
    
    
    37
    
    
    
    52
    
    
    
    52
    
    
    
    (93
    )
    
    
    48Net income (loss)
    
    
    219
    
    
    
    191
    
    
    
    445
    
    
    
    (1,678
    )
    
    
    (823
    )Net income (loss) available to common stockholders
    
    
    200
    
    
    
    191
    
    
    
    436
    
    
    
    (1,687
    )
    
    
    (860
    )Basic earnings per common shareNet income
    
    
    0.29
    
    
    
    0.27
    
    
    
    0.63
    
    
    
    (2.43
    )
    
    
    (1.24
    )Diluted earnings per common shareNet income (loss)
    
    
    0.29
    
    
    
    0.25
    
    
    
    0.58
    
    
    
    (2.43
    )
    
    
    (1.24
    )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
    
    
    
    1.53
  December 31, 2008.
 September 30, 2008.
 June 30, 2008.
 March 31, 2008.
 September 30, 2007.
 June 30, 2007.
 March 31, 2007.
 144




---



##### Table of Contents



Supplemental Natural Gas and Oil Operations (Unaudited)
  Capitalized Costs.
 BrazilUnited
    
    
    andStates
    
    
    Egypt(1)
    
    
    Worldwide2008Natural gas and oil properties:Costs subject to amortization
    
    $
    18,503
    
    
    $
    823
    
    
    $
    19,326Costs not subject to amortization
    
    
    326
    
    
    
    187
    
    
    
    51318,829
    
    
    
    1,010
    
    
    
    19,839Less accumulated depreciation, depletion and amortization
    
    
    14,692
    
    
    
    756
    
    
    
    15,448Net capitalized costs
    
    $
    4,137
    
    
    $
    254
    
    
    $
    4,3912007Natural 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
    
    
    $
    6,814
 
 (1)
    
    Capitalized costs for Egypt were $31 million and $14 million as of December 31,
2008 and 2007. Total Costs Incurred.
 United
    
    
    Brazil andStates
    
    
    Egypt(1)
    
    
    Worldwide2008Property acquisition costsProved properties
    
    $
    51
    
    
    $
    
    
    
    $
    51Unproved properties
    
    
    74
    
    
    
    1
    
    
    
    75Exploration costs
    
    
    438
    
    
    
    104
    
    
    
    542Development costs
    
    
    938
    
    
    
    93
    
    
    
    1,031Costs expended
    
    
    1,501
    
    
    
    198
    
    
    
    1,699Asset retirement obligation costs
    
    
    19
    
    
    
    
    
    
    
    19Total costs incurred
    
    $
    1,520
    
    
    $
    198
    
    
    $
    1,7182007Property 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
    
    
    $
    1,196
 
 (1)
    
    Costs incurred for Egypt were $26 million, $10 million and $4 million for the
years ended December 31, 2008, 2007 and 2006. 145




---



##### Table of Contents



Unevaluated Capitalized Costs.
  Cumulative
    
    
    Costs Excluded
    
    
    CumulativeBalance
    
    
    for Years Ended(1)
    
    
    BalanceDecember 31,
    
    
    December 31
    
    
    December 31,2008
    
    
    2008
    
    
    2007
    
    
    2006
    
    
    2005United StatesAcquisition
    
    $
    256
    
    
    $
    72
    
    
    $
    115
    
    
    $
    12
    
    
    $
    57Exploration
    
    
    70
    
    
    
    55
    
    
    
    6
    
    
    
    8
    
    
    
    1Development
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Total United States
    
    
    326
    
    
    
    127
    
    
    
    121
    
    
    
    20
    
    
    
    58Brazil & Egypt(2)Acquisition
    
    
    7
    
    
    
    
    
    
    
    4
    
    
    
    1
    
    
    
    2Exploration
    
    
    180
    
    
    
    76
    
    
    
    81
    
    
    
    14
    
    
    
    9Development
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Total Brazil & Egypt
    
    
    187
    
    
    
    76
    
    
    
    85
    
    
    
    15
    
    
    
    11Worldwide
    
    $
    513
    
    
    $
    203
    
    
    $
    206
    
    
    $
    35
    
    
    $
    69
 
 (1)
    
    Includes capitalized interest of $24 million, $33 million and $24 million for
the years ended December 31, 2008, 2007 and 2006.(2)
    
    Includes $31 million related to Egypt at December 31, 2008. Natural Gas and Oil Reserves.
  146




---



##### 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, 2006
    
    
    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
    
    
    
    2,853Revisions due to prices
    
    
    (136
    )
    
    
    (1
    )
    
    
    (137
    )
    
    
    (26,018
    )
    
    
    (29,406
    )
    
    
    (55,424
    )
    
    
    (985
    )
    
    
    (476
    )Revisions other than price
    
    
    (52
    )
    
    
    
    
    
    
    (52
    )
    
    
    (2,546
    )
    
    
    
    
    
    
    (2,546
    )
    
    
    (891
    )
    
    
    (72
    )Extensions and discoveries
    
    
    475
    
    
    
    
    
    
    
    475
    
    
    
    16,468
    
    
    
    
    
    
    
    16,468
    
    
    
    456
    
    
    
    577Purchases of reserves in
place
    
    
    10
    
    
    
    
    
    
    
    10
    
    
    
    1,295
    
    
    
    
    
    
    
    1,295
    
    
    
    68
    
    
    
    18Sales of reserves in place
    
    
    (224
    )
    
    
    
    
    
    
    (224
    )
    
    
    (10,440
    )
    
    
    
    
    
    
    (10,440
    )
    
    
    (2,754
    )
    
    
    (303
    )Production
    
    
    (230
    )
    
    
    (3
    )
    
    
    (233
    )
    
    
    (4,523
    )
    
    
    (124
    )
    
    
    (4,647
    )
    
    
    (1,849
    )
    
    
    (272
    )December 31, 2008
    
    
    2,091
    
    
    
    47
    
    
    
    2,138
    
    
    
    23,910
    
    
    
    3,180
    
    
    
    27,090
    
    
    
    4,159
    
    
    
    2,325Proved developed reservesDecember 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
    
    
    
    2,020December 31, 2008
    
    
    1,564
    
    
    
    12
    
    
    
    1,576
    
    
    
    19,799
    
    
    
    615
    
    
    
    20,414
    
    
    
    3,619
    
    
    
    1,720Unconsolidated investment in
Four StarDecember 31, 2008Net proved developed and
undeveloped reserves
    
    
    176
    
    
    
    
    
    
    
    176
    
    
    
    2,199
    
    
    
    
    
    
    
    2,199
    
    
    
    5,518
    
    
    
    222Proved developed reserves
    
    
    149
    
    
    
    
    
    
    
    149
    
    
    
    2,151
    
    
    
    
    
    
    
    2,151
    
    
    
    4,516
    
    
    
    189December 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
   147




---



##### Table of Contents



148




---



##### Table of Contents



Results of Operations.
 United
    
    
    BrazilStates
    
    
    and Egypt
    
    
    Worldwide2008Net Revenues(1)Sales to external customers
    
    $
    951
    
    
    $
    20
    
    
    $
    971Affiliated sales
    
    
    1,421
    
    
    
    
    
    
    
    1,421Total
    
    
    2,372
    
    
    
    20
    
    
    
    2,392Cost of
products and services(2)
    
    
    (79
    )
    
    
    
    
    
    
    (79
    )Production
costs(3)
    
    
    (354
    )
    
    
    (9
    )
    
    
    (363
    )Ceiling test
charges(4)
    
    
    (2,181
    )
    
    
    (488
    )
    
    
    (2,669
    )Depreciation, depletion and amortization
    
    
    (768
    )
    
    
    (14
    )
    
    
    (782
    )(1,010
    )
    
    
    (491
    )
    
    
    (1,501
    )Income tax
benefit(5)
    
    
    364
    
    
    
    
    
    
    
    364Results of operations from producing activities
    
    $
    (646
    )
    
    $
    (491
    )
    
    $
    (1,137
    )Equity
earnings from unconsolidated investment in Four Star(6)
    
    $
    (93
    )
    
    $
    
    
    
    $
    (93
    )Depreciation, depletion and amortization ($/Mcfe)(7)
    
    $
    2.87
    
    
    $
    3.62
    
    
    $
    2.882007Net Revenues(1)Sales to external customers
    
    $
    1,085
    
    
    $
    25
    
    
    $
    1,110Affiliated sales
    
    
    1,149
    
    
    
    (8
    )
    
    
    1,141Total
    
    
    2,234
    
    
    
    17
    
    
    
    2,251Cost of
products and services(2)
    
    
    (72
    )
    
    
    
    
    
    
    (72
    )Production
costs(3)
    
    
    (327
    )
    
    
    (11
    )
    
    
    (338
    )Depreciation, depletion and amortization
    
    
    (748
    )
    
    
    (16
    )
    
    
    (764
    )1,087
    
    
    
    (10
    )
    
    
    1,077Income tax (expense) benefit
    
    
    (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)(7)
    
    $
    2.63
    
    
    $
    3.10
    
    
    $
    2.642006Net Revenues(1)Sales to external customers
    
    $
    608
    
    
    $
    41
    
    
    $
    649Affiliated sales
    
    
    1,160
    
    
    
    (9
    )
    
    
    1,151Total
    
    
    1,768
    
    
    
    32
    
    
    
    1,800Cost of
products and services(2)
    
    
    (58
    )
    
    
    
    
    
    
    (58
    )Production
costs(3)
    
    
    (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)(7)
    
    $
    2.37
    
    
    $
    2.14
    
    
    $
    2.36
 
 (1)
    
    Excludes the effects of natural gas and oil derivative contracts.(2)
    
    Cost of products and services consists of transportation costs.(3)
    
    Production costs include lease operating costs and production related taxes, including ad valorem and severance taxes.(4)
    
    Includes $9 million related to Egypt.(5)
    
    See Note 5 for a description of the deferred tax valuation allowance recorded in 2008 associated with our Brazil net operating losses and ceiling test charge.(6)
    
    Includes a $125 million impairment charge related to Four Star.(7)
    
    Includes accretion expense on asset retirement obligations of
$0.05/Mcfe in 2008 and $0.07/Mcfe in 2007 and 2006. 149




---



##### Table of Contents



Standardized Measure of Discounted Future Net Cash Flows.
 UnitedStates
    
    
    Brazil
    
    
    Worldwide2008Future cash inflows(1)
    
    $
    11,667
    
    
    $
    242
    
    
    $
    11,909Future production costs
    
    
    (3,495
    )
    
    
    (45
    )
    
    
    (3,540
    )Future development costs
    
    
    (1,406
    )
    
    
    (65
    )
    
    
    (1,471
    )Future income tax expenses
    
    
    (1,152
    )
    
    
    (20
    )
    
    
    (1,172
    )Future net cash flows
    
    
    5,614
    
    
    
    112
    
    
    
    5,72610% annual discount for estimated timing of cash flows
    
    
    (2,274
    )
    
    
    (56
    )
    
    
    (2,330
    )Standardized measure of discounted future net cash flows
    
    $
    3,340
    
    
    $
    56
    
    
    $
    3,3962007Future 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
    
    
    $
    4,649Unconsolidated Investment in Four StarStandardized measure of discounted future net cash flows
2008
    
    $
    396
    
    
    $
    
    
    
    $
    3962007
    
    $
    444
    
    
    $
    
    
    
    $
    4442006
    
    $
    323
    
    
    $
    
    
    
    $
    323
 
 (1)
    
    The company had no commodity-based derivative contracts designated as
accounting hedges at December 31, 2008. United States excludes $61 million and $219 million
of future net cash inflows attributable to derivatives designated as accounting hedges in
years 2007 and 2006. Amounts also exclude the impact on future net cash flows of derivatives
not designated as accounting hedges.  150




---



##### Table of Contents



Changes in Standardized Measure of Discounted Future Net Cash Flows.
 Years Ended December 31,(1)2008
    
    
    2007
    
    
    2006(In millions)Sales and transfers of natural gas and oil produced net of production costs
    
    $
    (2,059
    )
    
    $
    (1,657
    )
    
    $
    (1,516
    )Net changes in prices and production costs
    
    
    (3,380
    )
    
    
    2,723
    
    
    
    (2,891
    )Extensions, discoveries and improved recovery, less related costs
    
    
    1,136
    
    
    
    910
    
    
    
    549Changes in estimated future development costs
    
    
    342
    
    
    
    (4
    )
    
    
    (55
    )Previously estimated development costs incurred during the period
    
    
    141
    
    
    
    200
    
    
    
    192Revision of previous quantity estimates
    
    
    (887
    )
    
    
    117
    
    
    
    (38
    )Accretion of discount
    
    
    622
    
    
    
    501
    
    
    
    827Net change in income taxes
    
    
    1,458
    
    
    
    (1,333
    )
    
    
    1,123Purchases of reserves in place
    
    
    36
    
    
    
    810
    
    
    
    4Sales of reserves in place
    
    
    (603
    )
    
    
    (7
    )
    
    
    (42
    )Change in production rates, timing and other
    
    
    (244
    )
    
    
    95
    
    
    
    (289
    )Net change
    
    $
    (3,438
    )
    
    $
    2,355
    
    
    $
    (2,136
    )
 
 (1)
    
    This disclosure reflects changes in the standardized measure calculation
excluding the effects of hedging activities. 151




---



##### Table of Contents



SCHEDULE II
 EL PASO CORPORATION
VALUATION AND QUALIFYING ACCOUNTS
 Years Ended December 31, 2008, 2007 and 2006
(In millions)
 Balance at
    
    Charged to
    
    
    
    
    
    Charged
    
    Balance atBeginning
    
    Costs and
    
    
    
    
    
    to Other
    
    End ofDescription
    
    of Period
    
    Expenses
    
    Deductions
    
    Accounts
    
    Period2008Allowance for doubtful accounts
    
    $
    17
    
    
    $
    (2
    )
    
    $
    
    
    
    $
    (6
    )
    
    $
    9Valuation allowance on deferred tax assets
    
    
    137
    
    
    
    202
    (1)
    
    
    
    
    
    
    (2
    )
    
    
    337Legal reserves(2)
    
    
    460
    
    
    
    (91
    )
    
    
    (16
    )
    
    
    (280
    )(4)
    
    
    73Environmental reserves
    
    
    260
    
    
    
    (11
    )
    
    
    (44
    )
    
    
    (1
    )
    
    
    204Regulatory reserves(5)
    
    
    10
    
    
    
    
    
    
    
    (10
    )
    
    
    
    
    
    
    2007Allowance for doubtful accounts
    
    $
    28
    
    
    $
    (4
    )
    
    $
    (5
    )(6)
    
    $
    (2
    )
    
    $
    17Valuation allowance on deferred tax assets
    
    
    127
    
    
    
    10
    
    
    
    
    
    
    
    
    
    
    
    137Legal reserves(2)
    
    
    548
    
    
    
    36
    
    
    
    (128
    )(3)
    
    
    4
    
    
    
    460Environmental reserves
    
    
    314
    
    
    
    21
    
    
    
    (75
    )
    
    
    
    
    
    
    260Regulatory reserves(5)
    
    
    65
    
    
    
    61
    
    
    
    (116
    )
    
    
    
    
    
    
    102006Allowance for doubtful accounts
    
    $
    65
    
    
    $
    (5
    )
    
    $
    (27
    )(6)
    
    $
    (5
    )
    
    $
    28Valuation allowance on deferred tax assets
    
    
    107
    
    
    
    23
    
    
    
    
    
    
    
    (3
    )
    
    
    127Legal reserves(2)
    
    
    574
    
    
    
    48
    
    
    
    (74
    )
    
    
    
    
    
    
    548Environmental reserves
    
    
    348
    
    
    
    30
    
    
    
    (64
    )
    
    
    
    
    
    
    314Regulatory reserves(5)
    
    
    1
    
    
    
    65
    
    
    
    (1
    )
    
    
    
    
    
    
    65
 
 (1)
    
    Amounts reflect valuation allowances associated with Brazil net operating
losses and ceiling test charges.(2)
    
    Amounts are net of related insurance receivables.(3)
    
    Included is the settlement of our shareholder litigation lawsuits.(4)
    
    Amount reclassified as SFAS No. 106 liability (see Note 14).(5)
    
    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.(6)
    
    Relates primarily to the sale of our accounts receivable under an accounts receivable sales program. 152




---



##### 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
  153




---



##### 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
  154




---



##### Table of Contents



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
    
    
    88Consolidated Statements of Income
    
    
    92Consolidated Balance Sheets
    
    
    93Consolidated Statements of Cash Flows
    
    
    95Consolidated Statements of Stockholders Equity
    
    
    96Consolidated Statements of Comprehensive Income
    
    
    97Notes to Consolidated Financial Statements
    
    
    982. Financial statement schedules and supplementary information required to be submitted
Schedule II  Valuation and Qualifying Accounts
    
    
    1523. Exhibits
    
    
    157
  Undertaking
  155




---



##### 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)
    
    March 2, 2009/s/ D. Mark Leland

D. Mark Leland
    
    Executive Vice President and Chief Financial
Officer (Principal Financial Officer)
    
    March 2, 2009/s/ John R. Sult
John R. Sult
    
    Senior Vice President and Controller
(Principal Accounting Officer)
    
    March 2, 2009/s/ Ronald L. Kuehn, Jr.
    
    Chairman of the Board
    
    March 2, 2009Ronald L. Kuehn, Jr./s/ Juan Carlos Braniff
    
    Director
    
    March 2, 2009Juan Carlos Braniff/s/ James L. Dunlap
    
    Director
    
    March 2, 2009James L. Dunlap/s/ Robert W. Goldman
    
    Director
    
    March 2, 2009Robert W. Goldman/s/ Anthony W. Hall, Jr.
    
    Director
    
    March 2, 2009Anthony W. Hall, Jr./s/ Thomas R. Hix
    
    Director
    
    March 2, 2009Thomas R. Hix/s/ William H. Joyce
    
    Director
    
    March 2, 2009William H. Joyce/s/ Ferrell P. McClean
    
    Director
    
    March 2, 2009Ferrell P. McClean/s/ Steven J. Shapiro
    
    Director
    
    March 2, 2009Steven J. Shapiro/s/ J. Michael Talbert
    
    Director
    
    March 2, 2009J. Michael Talbert/s/ Robert F. Vagt
    
    Director
    
    March 2, 2009Robert F. Vagt/s/ John L. Whitmire
    
    Director
    
    March 2, 2009John L. Whitmire/s/ Joe B. Wyatt
    
    Director
    
    March 2, 2009Joe B. Wyatt
 156




---



##### Table of Contents



EL PASO CORPORATION
 EXHIBIT INDEX
December 31, 2008
  ExhibitNumber
    
    Description3.A
    
    Second Amended and Restated Certificate of Incorporation (Exhibit 3.A to our
Current Report on Form 8-K filed with the SEC on May 31, 2005).3.B
    
    By-laws effective as of December 6, 2007 (Exhibit 3.B to our Current Report on
Form 8-K filed with the SEC on 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 Annual Report on Form
10-K for the year ended December 31, 2004, filed with the SEC on March 28, 2005).4.B
    
    Certificate of Designations of 4.99% Convertible Perpetual Preferred Stock
(Exhibit 3.A to our Current Report on Form 8-K filed with the SEC on 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 with the SEC on 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 Current Report on Form 8-K filed with
the SEC on 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 Quarterly Report on Form 10-Q for the
period ended September 30, 2006, filed with the SEC on November 6, 2006).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 Quarterly Report on Form 10-Q for the
period ended June 30, 2007, filed with the SEC on August 7, 2007).4.G
    
    Thirteenth Supplemental Indenture dated as of May 30, 2008 between El Paso
Corporation and HSBC Bank USA, National Association, as trustee, to Indenture
dated as of May 10, 1999 (Exhibit 4 to our Quarterly Report on Form 10-Q for the
period ended June 30, 2008, filed with the SEC on August 8, 2008).*4.H
    
    Fourteenth Supplemental Indenture dated as of December 12, 2008 between El Paso
Corporation and HSBC Bank USA, National Association, as trustee, to Indenture
dated as of May 10, 1999.*4.I
    
    Fifteenth Supplemental Indenture, dated as of February 9, 2009 between El Paso
Corporation and HSBC Bank USA, National Association, as trustee, to Indenture
dated as of May 10, 1999.
 157




---



##### Table of Contents



ExhibitNumber
    
    Description+10.A
    
    1995 Compensation Plan for Non-Employee Directors Amended and Restated effective
as of December 4, 2003 (Exhibit 10.F to our Annual Report on Form 10-K for the
year ended December 31, 2003, filed with the SEC on September 30, 2004); 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
(Exhibit 10.A.1 to our Annual Report on Form 10-K for the year ended December 31,
2007, filed with the SEC on February 28, 2008).*+10.A.1
    
    Amendment No. 2 effective as of January 1, 2008 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 Annual Report on Form 10-K for the year
ended December 31, 2004, filed with the SEC on March 28, 2005); Amendment No. 1
effective as of July 16, 1999 to the Stock Option Plan for Non-Employee Directors
(Exhibit 10.G.1 to our Annual Report on Form 10-K for the year ended December 31,
2004, filed with the SEC on March 28, 2005); Amendment No. 2 effective as of
February 7, 2001 to the Stock Option Plan for Non-Employee Directors (Exhibit
10.B.2 to our Annual Report on Form 10-K for the year ended December 31, 2007,
filed with the SEC on February 28, 2008); Amendment No. 3 effective as of October
26, 2006 to the Stock Option Plan for Non-Employee Directors (Exhibit 10.N to our
Quarterly Report on Form 10-Q for the period ended on September 30, 2006, filed
with the SEC on November 6, 2006).*+10.C
    
    2001 Stock Option Plan for Non-Employee Directors effective as of January 29, 2001.+10.C.1
    
    Amendment No. 1 effective as of February 7, 2001 to the 2001 Stock Option Plan for
Non-Employee Directors (Exhibit 10.C.1 to our Annual Report on Form 10-K for the
year ended December 31, 2007, filed with the SEC on February 28, 2008).+10.C.2
    
    Amendment No. 2 effective as of December 4, 2003 to the 2001 Stock Option Plan for
Non-Employee Directors (Exhibit 10.C.2 to our Annual Report on Form 10-K for the
year ended December 31, 2007, filed with the SEC on February 28, 2008).+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 Quarterly Report on Form 10-Q for the
period ended September 30, 2006, filed with the SEC on November 6, 2006).+10.D
    
    1995 Omnibus Compensation Plan Amended and Restated effective as of August 1, 1998
(Exhibit 10.I to our Annual Report on Form 10-K for the year ended December 31,
2004, filed with the SEC on March 28, 2005); Amendment No. 1 effective as of
December 3, 1998 to the 1995 Omnibus Compensation Plan (Exhibit 10.I.1 to our
Annual Report on Form 10-K for the year ended December 31, 2004, filed with the
SEC on March 28, 2005); Amendment No. 2 effective as of January 20, 1999 to the
1995 Omnibus Compensation Plan (Exhibit 10.I.2 to our Annual Report on Form 10-K
for the year ended December 31, 2004, filed with the SEC on March 28, 2005);
Amendment No. 3 effective as of October 26, 2006 to the 1995 Omnibus Compensation
Plan (Exhibit 10.L to our Quarterly Report on Form 10-Q for the period ended
September 30, 2006, filed with the SEC on November 6, 2006).+10.E
    
    1999 Omnibus Incentive Compensation Plan dated January 20, 1999 (Exhibit 10.E to our Annual
Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28,
2008).+10.E.1
    
    Amendment No. 1 effective as of February 7, 2001 to the 1999 Omnibus Incentive Compensation Plan
(Exhibit 10.E.1 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed
with the SEC on February 28, 2008).*+10.E.2
    
    Amendment No. 2 effective as of May 1, 2003 to the 1999 Omnibus Incentive Compensation Plan
 158




---



##### Table of Contents



ExhibitNumber
    
    Description+10.E.3
    
    Amendment No. 3 effective as of October 26, 2006 to the 1999 Omnibus Incentive Compensation Plan
(Exhibit 10.K to our Quarterly Report on Form 10-Q for the period ended September 30, 2006,
filed with the SEC on November 6, 2006).+10.F
    
    2001 Omnibus Incentive Compensation Plan effective as of January 29, 2001 (Exhibit 10.F. to our
Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February
28, 2008).+10.F.1
    
    Amendment No. 1 effective as of February 7, 2001 to the 2001 Omnibus Incentive Compensation Plan
(Exhibit 10.F.1 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed
with the SEC on February 28, 2008).+10.F.2
    
    Amendment No. 2 effective as of April 1, 2001 to the 2001 Omnibus Incentive Compensation Plan
(Exhibit 10.F.2 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed
with the SEC on February 28, 2008).+10.F.3
    
    Amendment No. 3 effective as of July 17, 2002 to the 2001 Omnibus Incentive Compensation Plan
(Exhibit 10.F.3 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed
with the SEC on February 28, 2008).*+10.F.4
    
    Amendment No. 4 effective as of May 1, 2003 to the 2001 Omnibus Incentive Compensation Plan.*+10.F.5
    
    Amendment No. 5 effective as of March 8, 2004 to the 2001 Omnibus Incentive Compensation Plan.+10.F.6
    
    Amendment No. 6 effective as of October 26, 2006 to the 2001 Omnibus Incentive Compensation Plan
(Exhibit 10.M to our Quarterly Report on Form 10-Q for the period ended September 30, 2006,
filed with the SEC on November 6, 2006).+10.G
    
    Supplemental Benefits Plan Amended and Restated effective December 7, 2001 (Exhibit 10.G to our
Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February
28, 2008); Amendment No. 1 effective as of November 7, 2002 to the Supplemental Benefits Plan
(Exhibit 10.G.1 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed
with the SEC on February 28, 2008); Amendment No. 2 effective as of June 1, 2004 to the
Supplemental Benefits Plan (Exhibit 10.L.1 to our Annual Report on Form 10-K for the year ended
December 31, 2004, filed with the SEC on March 28, 2005); Amendment No. 3 effective December 17,
2004 to the Supplemental Benefits Plan (Exhibit 10.UU to our Quarterly Report on Form 10-Q for
the period ended September 30, 2004, filed with the SEC on December 20, 2004); Amendment No. 4
to the Supplemental Benefits Plan effective as of December 31, 2004 (Exhibit 10.I.1 to our
Annual Report on Form 10-K for the year ended December 31, 2005, filed with the SEC on March 7,
2006); Amendment No. 5 effective as of January 1, 2007 to the Supplemental Benefits Plan Amended
and Restated effective December 7, 2001 (Exhibit 10.G.5 to our Annual Report on Form 10-K for
the year ended December 31, 2007, filed with the SEC on February 28, 2008).+10.H
    
    Senior Executive Survivor Benefit Plan Amended and Restated effective as of August 1, 1998
(Exhibit 10.M to our Annual Report on Form 10-K for the year ended December 31, 2004, filed with
the SEC on March 28, 2005); Amendment No. 1 effective as of February 7, 2001 to the Senior
Executive Survivor Benefit Plan (Exhibit 10.H.1 to our Annual Report on Form 10-K for the year
ended December 31, 2007, filed with the SEC on February 28, 2008); Amendment No. 2 effective as
of October 1, 2002 to the Senior Executive Survivor Benefit Plan (Exhibit 10.H.2 to our Annual
Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 28,
2008).+10.I
    
    Key Executive Severance Protection Plan Amended and Restated effective as of August 1, 1998
(Exhibit 10.N to our Annual Report on Form 10-K for the year ended December 31, 2004, filed with
the SEC on March 28, 2005).+10.I.1
    
    Amendment No. 1 effective as of February 7, 2001 to the Key Executive Severance Protection Plan
(Exhibit 10.I.1 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed
with the SEC on February 28, 2008).
 159




---



##### Table of Contents



ExhibitNumber
    
    Description+10.I.2
    
    Amendment No. 2 effective as of November 7, 2002 to the Key Executive Severance Protection Plan
(Exhibit 10.I.2 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed
with the SEC on February 28, 2008).+10.I.3
    
    Amendment No. 3 effective as of December 6, 2002 to the Key Executive Severance Protection Plan
(Exhibit 10.I.3 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed
with the SEC on February 28, 2008).*+10.I.4
    
    Amendment No. 4 effective as of September 2, 2003 to the Key Executive Severance Protection Plan.+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 (Exhibit 10.I.5 to our Annual Report on Form
10-K for the year ended December 31, 2007, filed with the SEC on February 28, 2008).+10.J
    
    2004 Key Executive Severance Protection Plan effective as of March 9, 2004 (Exhibit 10.P to our
Annual Report on Form 10-K for the year ended December 31, 2003, filed with the SEC on September
30, 2004); Amendment No. 1 effective as of January 1, 2007 to the 2004 Key Executive Severance
Protection Plan effective as of March 9, 2004 (Exhibit 10.J.1 to our Annual Report on Form 10-K
for the year ended December 31, 2007, filed with the SEC on February 28, 2008).+10.K
    
    Director Charitable Award Plan Amended and Restated effective as of August 1,
1998 (Exhibit 10.P to our Annual Report on Form 10-K for the year ended
December 31, 2004, filed with the SEC on March 28, 2005); Amendment No. 1
effective as of February 7, 2001 to the Director Charitable Award Plan
(Exhibit 10.K.1 to our Annual Report on Form 10-K for the year ended December
31, 2007, filed with the SEC on February 28, 2008); Amendment No. 2 effective
as of December 4, 2003 to the Director Charitable Award Plan (Exhibit 10.Q.1
to our Annual Report on Form 10-K for the year ended December 31, 2003, filed
with the SEC on September 30, 2004).+10.L
    
    Strategic Stock Plan Amended and Restated effective as of December 3, 1999
(Exhibit 10.L to our Annual Report on Form 10-K for the year ended December
31, 2007, filed with the SEC on February 28, 2008); Amendment No. 1 effective
as of February 7, 2001 to the Strategic Stock Plan (Exhibit 10.L.1 to our
Annual Report on Form 10-K for the year ended December 31, 2007, filed with
the SEC on February 28, 2008); Amendment No. 2 effective as of November 7,
2002 to the Strategic Stock Plan (Exhibit 10.L.2 to our Annual Report on Form
10-K for the year ended December 31, 2007, filed with the SEC on February 28,
2008); Amendment No. 3 effective as of December 6, 2002 to the Strategic Stock
Plan (Exhibit 10.L.3 to our Annual Report on Form 10-K for the year ended
December 31, 2007, filed with the SEC on February 28, 2008); Amendment No. 4
effective as of January 29, 2003 to the Strategic Stock Plan (Exibit 10.L.4 to
our Annual Report on Form 10-K for the year ended December 31, 2007, filed
with the SEC on February 28, 2008); Amendment No. 5 effective as of October
26, 2006 to the Strategic Stock Plan (Exhibit 10.J to our Quarterly Report on
Form 10-Q for the period ended September 30, 2006, filed with the SEC on
November 6, 2006).+10.M
    
    Domestic Relocation Policy effective November 1, 1996 (Exhibit 10.R to our
Annual Report on Form 10-K for the year ended December 31, 2004, filed with
the SEC on March 28, 2005).+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 Annual Report on Form
10-K for the year ended December 31, 2004, filed with the SEC on March 28,
2005); Termination of the Executive Award Plan of Sonat Inc. (Exhibit 10.N.1
to our Annual Report on Form 10-K for the year ended December 31, 2007, filed
with the SEC on February 28, 2008); Amendment to the Executive Award Plan of
Sonat Inc. effective as of October 26, 2006 (Exhibit 10.H to our Quarterly
Report on Form 10-Q for the period ended September 30, 2006, filed with the
SEC on November 6, 2006).
 160




---



##### Table of Contents



ExhibitNumber
    
    Description+10.O
    
    Omnibus Plan for Management Employees Amended and Restated effective as of
December 3, 1999 (Exhibit 10.O to our Annual Report on Form 10-K for the year
ended December 31, 2007, filed with the SEC on February 28, 2008); Amendment
No. 1 effective as of December 1, 2000 to the Omnibus Plan for Management
Employees (Exhibit 10.O.1 to our Annual Report on Form 10-K for the year ended
December 31, 2007, filed with the SEC on February 28, 2008); Amendment No. 2
effective as of February 7, 2001 to the Omnibus Plan for Management Employees
(Exhibit 10.O.2 to our Annual Report on Form 10-K for the year ended December
31, 2007, filed with the SEC on February 28, 2008); Amendment No. 3 effective
as of December 7, 2001 to the Omnibus Plan for Management (Exhibit 10.O.3 to
our Annual Report on Form 10-K for the year ended December 31, 2007, filed
with the SEC on February 28, 2008); Amendment No. 4 effective as of December
6, 2002 to the Omnibus Plan for Management Employees (Exhibit 10.O.4 to our
Annual Report on Form 10-K for the year ended December 31, 2007, filed with
the SEC on February 28, 2008); Amendment No. 5 effective as of October 26,
2006 to the Corporation Omnibus Plan for Management Employees (Exhibit 10.I to
our Quarterly Report on Form-Q for the period ended September 30, 2006, filed
with the SEC on November 6, 2006).*+10.P
    
    Severance Pay Plan Amended and Restated effective as of October 1, 2002.+10.P.1
    
    Amendment No. 1 effective January 1, 2007 to the Severance Pay Plan Amended
and Restated effective as of October 1, 2002 (Exhibit 10.P.1 to our Annual
Report on Form 10-K for the year ended December 31, 2007, filed with the SEC
on February 28, 2008).*+10.P.2
    
    Amendment No. 2 effective January 1, 2008 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 Current Report on Form 8-K filed with the
SEC October 16, 2006).*+10.R
    
    Letter Agreement dated July 15, 2003 between El Paso and Douglas L. Foshee.*+10.S
    
    Letter Agreement dated December 18, 2003 between El Paso and Douglas L. Foshee.*+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.+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 Quarterly Report on Form 10-Q for the period ended September
30, 2006, filed with the SEC on November 6, 2006).+10.V
    
    Indemnification Agreement executed by El Paso for the benefit of Douglas L.
Foshee, effective December 17, 2004 (Exhibit 10.XX to our Quarterly Report
on Form 10-Q for the period ended September 30, 2004, filed with the SEC on
December 20, 2004).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 Annual Report on Form 10-K
for the year ended December 31, 2003, filed with the SEC on September 30,
2004).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 Current
Report on Form 8-K filed with the SEC on April 15, 2005).
 161




---



##### Table of Contents



ExhibitNumber
    
    Description+10.Y
    
    El Paso Corporation 2005 Compensation Plan for Non-Employee Directors
effective as of May 26, 2005 (Exhibit 10.A to our Current Report on Form
8-K filed with the SEC 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 Quarterly Report on Form 10-Q for
the period ended September 30, 2006, filed with the SEC on November 6,
2006); 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 (Exhibit 10.Y.1 to our Annual Report on Form 10-K for the
year ended December 31, 2007, filed with the SEC on February 28, 2008).*+10.Y.1
    
    Amendment No. 3 effective as of January 1, 2008 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 Current Report on Form 8-K filed with
the SEC on 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
Annual Report on Form 10-K for the year ended December 31, 2004, filed with
the SEC on March 28, 2005); Amendment No. 2 to the El Paso Corporation 2005
Omnibus Incentive Compensation Plan effective as of October 26, 2006
(Exhibit 10.Q to our Quarterly Report on Form 10-Q for the period ended
September 30, 2006, filed with the SEC on November 6, 2006); Amendment No.
3 to the El Paso Corporation 2005 Omnibus Incentive Compensation Plan
effective as of May 26, 2005 (Exhibit 10.Z.1 to our Annual Report on Form
10-K for the year ended December 31, 2007, filed with the SEC on February
28, 2008).+10.AA
    
    El Paso Corporation Employee Stock Purchase Plan, Amended and Restated
Effective as of July 1, 2005 (Exhibit 10.E to our Quarterly Report on Form
10-Q for the period ended June 30, 2005, filed with the SEC on August 5,
2005); Amendment No. 1 to the El Paso Corporation Employee Stock Purchase
Plan effective as of October 26, 2006 (Exhibit 10.G to our Quarterly Report
on Form 10-Q for the period ended September 30, 2006, filed with the SEC on
November 6, 2006).+10.BB
    
    2005 Supplemental Benefits Plan effective as of January 1, 2005 (Exhibit
10.KK to our Annual Report on Form 10-K for the year ended December 31,
2004, filed with the SEC on March 28, 2005); Amendment No. 1 effective as
of January 1, 2007 to the 2005 Supplemental Benefits Plan effective as of
January 1, 2005 (Exhibit 10.BB.1 to our Annual Report on Form 10-K for the
year ended December 31, 2007, filed with the SEC on February 28, 2008).*+10.BB.1
    
    Amendment No. 2 effective as of January 1, 2008 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
Current Report on Form 8-K filed with the SEC on 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 Current
Report on Form 8-K filed with the SEC on 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 Current Report on Form 8-K filed with
the SEC on November 21, 2007).
 162




---



##### Table of Contents



ExhibitNumber
    
    Description10.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 Current
Report on Form 8-K filed with the SEC on 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 Current Report on Form 8-K filed with
the SEC on 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 Current Report on Form
8-K filed with the SEC on December 29, 2006).*12
    
    Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.*21
    
    Subsidiaries of El Paso Corporation.*23.A
    
    Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP.*23.B
    
    Consent of Independent Registered
Public Accounting Firm, PricewaterhouseCoopers, LLP (Four Star)*23.C
    
    Consent of Ryder Scott Company, L.P.*23.D
    
    Consent of Independent Registered
Public Accounting Firm, PricewaterhouseCoopers (Citrus)

*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, 2008.*99.B
    
    Ryder Scott reserve report for Four Star Oil & Gas Company as of December 31, 2008.
 163