<PAGE>

--------------------------------------------------------------------------------
--------------------------------------------------------------------------------

                                 UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                             ---------------------

                                   FORM 10-K

(MARK ONE)
[X]             ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
                      THE SECURITIES EXCHANGE ACT OF 1934

                  FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003

                                       OR

[ ]           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 1-7176

                              EL PASO CGP COMPANY
             (Exact Name of Registrant as Specified in Its Charter)

<Table>
<S>                                              <C>
                    DELAWARE                                        74-1734212
        (State or Other Jurisdiction of                          (I.R.S. Employer
         Incorporation or Organization)                        Identification No.)

                EL PASO BUILDING
             1001 LOUISIANA STREET
                 HOUSTON, TEXAS                                       77002
    (Address of Principal Executive Offices)                        (Zip Code)
</Table>

                        TELEPHONE NUMBER: (713) 420-2600

        SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: NONE

        SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE

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

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

     Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act).  Yes [ ]  No [X]

     STATE THE AGGREGATE MARKET VALUE OF THE VOTING AND NON-VOTING COMMON EQUITY
HELD BY NON-AFFILIATES OF THE REGISTRANT: NONE

     INDICATE THE NUMBER OF SHARES OUTSTANDING OF EACH OF THE REGISTRANT'S
CLASSES OF COMMON STOCK, AS OF THE LATEST PRACTICABLE DATE.

     Common Stock, par value $1 per share. Shares outstanding on October 11,
2004: 1,000

                   DOCUMENTS INCORPORATED BY REFERENCE: NONE

--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
<PAGE>

                              EL PASO CGP COMPANY

                               TABLE OF CONTENTS

<Table>
<Caption>
                                      CAPTION                             PAGE
                                      -------                             ----
<S>         <C>                                                           <C>
                                    PART I

Item 1.     Business....................................................    1
Item 2.     Properties..................................................   19
Item 3.     Legal Proceedings...........................................   19
Item 4.     Submission of Matters to a Vote of Security Holders.........   20

                                   PART II

Item 5.     Market for Registrant's Common Equity and Related
              Stockholder Matters.......................................   20
Item 6.     Selected Financial Data.....................................   20
Item 7.     Management's Discussion and Analysis of Financial Condition
              and Results of Operations.................................   22
            Risk Factors and Cautionary Statement for Purposes of the
              "Safe Harbor" Provisions of the Private Securities
              Litigation Reform Act of 1995.............................   43
Item 7A.    Quantitative and Qualitative Disclosures About Market
              Risk......................................................   52
Item 8.     Financial Statements and Supplementary Data.................   54
Item 9.     Changes in and Disagreements with Accountants on Accounting
              and Financial Disclosure..................................  122
Item 9A.    Controls and Procedures.....................................  122
Item 9B.    Other Information...........................................  124

                                   PART III

Item 10.    Directors and Executive Officers of the Registrant..........  124
Item 11.    Executive Compensation......................................  126
Item 12.    Security Ownership of Certain Beneficial Owners and
              Management and Related Stockholder Matters................  135
Item 13.    Certain Relationships and Related Transactions..............  136
Item 14.    Principal Accountant Fees and Services......................  136

                                   PART IV

Item 15.    Exhibits, Financial Statement Schedules, and Reports on Form
              8-K.......................................................  137
            Signatures..................................................  141
</Table>

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

<Table>
<S>      <C>
/d       = per day
Bbl      = barrels
BBtu     = billion British thermal units
BBtue    = billion British thermal unit
           equivalents
Bcf      = billion cubic feet
Bcfe     = billion cubic feet of natural gas
           equivalents
Km       = kilometers
MBbls    = thousand barrels
Mcf      = thousand cubic feet
Mcfe     = thousand cubic feet of natural gas
           equivalents
Mgal     = thousand gallons
MMBbls   = million barrels
MMBtu    = million British thermal units
MMcf     = million cubic feet
MMcfe    = million cubic feet of natural gas
           equivalents
MMwh     = thousand megawatt hours
MTons    = thousand tons
MW       = megawatt
TBtu     = trillion British thermal units
Tcfe     = trillion cubic feet of natural gas
           equivalents
</Table>

    When we refer to natural gas and oil in "equivalents," we are doing so to
compare quantities of oil with quantities of natural gas or to express these
different commodities in a common unit. In calculating equivalents, we use a
generally recognized standard in which one Bbl of oil is equal to six Mcf of
natural gas. Oil includes natural gas liquids unless otherwise specified. Also,
when we refer to cubic feet measurements, all measurements are at a pressure of
14.73 pounds per square inch.

    When we refer to "us", "we", "our", "ours", "CGP" or "Coastal", we are
describing El Paso CGP Company and/or our subsidiaries.

                                        i
<PAGE>

RESTATEMENT OF HISTORICAL FINANCIAL INFORMATION

     In February 2004, we completed the December 31, 2003 reserve estimation
process for the proved natural gas and oil reserves in our Production segment.
The results of this process indicated that a significant downward revision to
our proved reserve estimates was needed. After an investigation into the factors
that caused this revision, we determined that a material portion of the downward
reserve revisions should be reflected in historical periods. Accordingly, we
restated our historical financial information for the years from 1999 to 2002
and for the first nine months of 2003. The investigation determined that certain
personnel used aggressive, and at times, unsupportable methods to book proved
reserves. In some instances, certain personnel provided historical proved
reserve estimates that they knew or should have known were incorrect at the time
they were reported. The investigation also found that we did not, in some cases,
maintain adequate documentation and records to support historically booked
proved natural gas and oil reserves.

     As a result of these conclusions, we restated our historical proved natural
gas and oil reserve estimates and the financial information derived from these
estimates for the periods from 1999 to 2002 and for the first nine months of
2003. The total cumulative impact of the restatement was a reduction of our
previously reported stockholder's equity as of September 30, 2003 of
approximately $1.1 billion. The restatement had no impact on our overall cash
flows during these periods. These restated amounts have been reflected only in
this Annual Report on Form 10-K, and we did not revise our historically filed
reports for the impacts of this restatement. Consequently, you should not rely
on historical information contained in those prior filings since this filing
replaces and revises those historically reported amounts.

     For a further discussion of the impact of the restatement on our selected
financial information, see Part II, Item 6, Selected Financial Data; for a more
detailed discussion of the factors leading to the restatement, the restatement
methods used and the financial impacts of the restatement, see Item 8, Financial
Statements and Supplementary Data, Note 1; and for a discussion of control
weaknesses that contributed to this issue and changes we have made or are in the
process of making to our control procedures, see Item 9A, Controls and
Procedures.

                                     PART I

ITEM 1. BUSINESS

                                    GENERAL

     We are a Delaware corporation originally founded in 1955. In January 2001,
we became a wholly owned subsidiary of El Paso Corporation (El Paso) through our
merger with a wholly owned El Paso subsidiary.

                               BUSINESS SEGMENTS

     For the years ended December 31, 2003, we operated through four business
segments -- Pipelines, Production, Field Services and Merchant Energy. Through
these segments, we provide the following energy related services:

Interstate Natural Gas
Transmission
  and Storage Services           We own or have interests in approximately
                                 17,300 miles of pipeline and approximately 280
                                 Bcf of storage capacity. We provide customers
                                 with interstate natural gas transmission and
                                 storage services from a diverse group of supply
                                 regions to major markets in the Midwest and
                                 western United States.

Production                       We own or have interests in approximately 3.9
                                 million net developed and undeveloped acres,
                                 and had over 1.0 Tcfe of proved natural gas and
                                 oil reserves worldwide at the end of 2003.
                                 During 2003, our production averaged
                                 approximately 530 MMcfe/d. During the first
                                 eight months of 2004, production averaged 367
                                 MMcfe/d.

                                        1
<PAGE>

Midstream Services               Our midstream businesses provide gathering and
                                 processing services primarily in south
                                 Louisiana.

Power Generation and Supply      Our power business owns or manages over 4,000
                                 MW of gross generating capacity in 8 countries.
                                 Our plants serve customers under long-term and
                                 market-based contracts or sell to the open
                                 market in spot market transactions. This
                                 business also manages power supply arrangements
                                 with electric utility customers to meet their
                                 peak electricity requirements. We have sold or
                                 expect to sell substantially all of our
                                 domestic power business in 2004.

     In addition to our operating segments, we also have discontinued
operations. These discontinued operations include our petroleum markets
business, which owned and operated refineries in the northeastern U.S. and in
Aruba, with a capacity to refine over 430,000 Bbls of oil per day. We completed
the sale of substantially all of this business in early 2004.

     Below is a description of each of our existing business segments. Our
current business segments are strategic business units that provide a variety of
energy products and services. We manage each segment separately and each segment
requires different technology and marketing strategies. For additional
discussion of our business segments, see Part II, Item 7, Management's
Discussion and Analysis of Financial Condition and Results of Operations. For
our segment operating results and identifiable assets, see Part II, Item 8,
Financial Statements and Supplementary Data, Note 21, which is incorporated
herein by reference.

PIPELINES SEGMENT

     Our Pipelines segment provides natural gas transmission, storage and
related services and owns or has interests in approximately 17,300 miles of
interstate natural gas pipelines in the U.S. Our systems connect several of the
nation's principal natural gas supply regions to several large consuming regions
in the U.S. and include access between our U.S. based systems and Canada. In
addition, we own or have interests in approximately 280 Bcf of storage capacity
used to provide a variety of flexible services to our customers. We conduct our
activities primarily through three wholly owned and one partially owned
interstate transmission systems along with four underground natural gas storage
entities. The tables below detail our wholly owned and partially owned
interstate transmission systems:

  Wholly Owned Interstate Transmission Systems

<Table>
<Caption>
                                                                        AS OF DECEMBER 31, 2003
                                                                     ------------------------------   AVERAGE THROUGHPUT(1)
     TRANSMISSION                        SUPPLY AND                  MILES OF    DESIGN    STORAGE    ---------------------
        SYSTEM                         MARKET REGION                 PIPELINE   CAPACITY   CAPACITY   2003    2002    2001
     ------------                      -------------                 --------   --------   --------   -----   -----   -----
                                                                                (MMCF/D)    (BCF)           (BBTU/D)
<S>                      <C>                                         <C>        <C>        <C>        <C>     <C>     <C>
ANR Pipeline             Extends from Louisiana, Oklahoma, Texas     10,600      6,414      202       4,232   4,130   4,531
  (ANR)                  and the Gulf of Mexico to the midwestern
                         and northern regions of the U.S.,
                         including the metropolitan areas of
                         Detroit, Chicago and Milwaukee.
Colorado Interstate Gas  Extends from most production areas in the    4,000      3,100      29        1,685   1,687   1,569
  (CIG)                  Rocky Mountain region and the Anadarko
                         Basin to the front range of the Rocky
                         Mountains and multiple interconnects with
                         pipeline systems transporting gas to the
                         Midwest, the Southwest, California and the
                         Pacific Northwest.
Wyoming Interstate       Extends from western Wyoming and the          600       1,880      --        1,213   1,194   1,017
  (WIC)                  Powder River Basin to various pipeline
                         interconnections near Cheyenne, Wyoming.
</Table>

---------------
(1) Includes throughput transported on behalf of affiliates.

                                        2
<PAGE>

     We also have five pipeline expansion projects underway as of September 2004
that have been approved by the Federal Energy Regulatory Commission (FERC):

<Table>
<Caption>
TRANSMISSION                                                                                                ANTICIPATED
   SYSTEM           PROJECT         CAPACITY                        DESCRIPTION(1)                        COMPLETION DATE
------------        -------         --------                        --------------                        ---------------
                                    (MMCF/D)
<S>           <C>                   <C>        <C>                                                        <C>
ANR            WestLeg Wisconsin      218      To increase capacity of ANR's existing system by looping   November 2004
                   expansion                   the Madison lateral and by enlarging the Beloit lateral
                                               through abandonment and replacement.
               EastLeg Wisconsin      142      To replace 4.7 miles of an existing 14-inch natural gas    November 2005
                   expansion                   pipeline with a 30-inch line in Washington County, add
                                               3.5 miles of 8-inch looping on the Denmark Lateral in
                                               Brown County, and modify ANR's existing Mountain
                                               Compressor Station in Oconto County, Wisconsin.
              NorthLeg Wisconsin       --      To add 6,000 horse power of electric powered compression   November 2005
                   expansion                   at ANR's Weyauwega Compressor station in Waupaca County,
                                               Wisconsin
CPG           Cheyenne Plains Gas     576      To construct a 36-inch pipeline to transport gas from the  December 2004
                Pipeline (CPG)                 Cheyenne hub in Colorado to interconnecting pipelines
                                               near Greensburg, Kansas.
                Cheyenne Plains       176      To add approximately 10,300 horsepower of compression to   December 2005
                   expansion                   the Cheyenne Plains project.
</Table>

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

  Partially Owned Interstate Transmission System

<Table>
<Caption>
                                                                          AS OF DECEMBER 31, 2003
                                                                     ----------------------------------   AVERAGE THROUGHPUT(2)
        TRANSMISSION                       SUPPLY AND                OWNERSHIP   MILES OF     DESIGN      ---------------------
           SYSTEM                         MARKET REGION              INTEREST    PIPELINE   CAPACITY(2)   2003    2002    2001
        ------------                      -------------              ---------   --------   -----------   -----   -----   -----
                                                                     (PERCENT)               (MMCF/D)           (BBTU/D)
<S>                           <C>                                    <C>         <C>        <C>           <C>     <C>     <C>
Great Lakes Gas               Extends from the Manitoba-Minnesota       50        2,115        2,895      2,366   2,378   2,224
  Transmission(1)             border to the Michigan-Ontario border
                              at St. Clair, Michigan.
</Table>

---------------
(1) This system is accounted for as an equity investment.
(2) Volumes represent the system's total design capacity and average throughput
    and are not adjusted for our ownership interest.

     In addition to the storage capacity on our transmission systems, we own or
have interests in the following natural gas storage entities:

  Underground Natural Gas Storage Entities

<Table>
<Caption>
                                                              AS OF DECEMBER 31, 2003
                                                              -----------------------
                                                              OWNERSHIP     STORAGE
STORAGE ENTITY                                                INTEREST    CAPACITY(1)   LOCATION
--------------                                                ---------   -----------   --------
                                                              (PERCENT)      (BCF)
<S>                                                           <C>         <C>           <C>
ANR Storage................................................    100          56          Michigan
Blue Lake Gas Storage(2)...................................     75          47          Michigan
Eaton Rapids Gas Storage(2)................................     50          13          Michigan
Young Gas Storage(2).......................................     48           6          Colorado
</Table>

---------------
(1) Includes a total of 75 Bcf contracted to affiliates. Storage capacity is
    under long-term contracts and is not adjusted for our ownership interest.
(2) These systems are accounted for as equity investments as of December 31,
    2003.

     In addition to these interests in interstate natural gas transmission and
storage facilities, we have a 50 percent interest in Wyco Development, L.L.C.
(Wyco). Wyco owns the Front Range Pipeline, a state-regulated gas pipeline
extending from the Cheyenne Hub to Public Service Company of Colorado's (PSCo)

                                        3
<PAGE>

Fort St. Vrain electric generation plant, and also owns compression facilities
on WIC's Medicine Bow Lateral. These facilities are leased to PSCo and WIC,
respectively, under long-term leases. Our equity investment in Wyco is
approximately $24 million.

Regulatory Environment

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

     - rates and charges for natural gas transportation, storage and related
       services;

     - certification and construction of new facilities;

     - extension or abandonment of facilities;

     - maintenance of accounts and records;

     - relationships between pipeline and energy affiliates;

     - terms and conditions of service;

     - depreciation and amortization policies;

     - acquisition and disposition of facilities; and

     - initiation and discontinuation of services.

     The fees or rates established under our tariffs are a function of our costs
of providing services to our customers, including a reasonable return on our
invested capital. Our revenues from transportation, storage and related services
(transportation services revenues) consist of reservation revenues and usage
revenues. Reservation revenues are from customers (referred to as firm
customers) whose contracts (which are for varying terms) reserve capacity on our
pipeline systems or storage facilities. These firm customers are obligated to
pay a monthly reservation or demand charge, regardless of the amount of natural
gas they transport or store, for the term of their contracts. Usage revenues are
from both firm customers and interruptible customers (those without reserved
capacity) who pay charges based on the volume of gas actually transported,
stored, injected or withdrawn. In 2003, approximately 90 percent of our
transportation services revenues were attributable to charges paid by firm
customers. The remaining 10 percent of our transportation services revenue was
attributable to usage charges paid by both firm and interruptible customers. Due
to our regulated nature, our financial results have historically been relatively
stable. However, these results can be subject to volatility due to factors such
as weather, changes in natural gas prices and market conditions, regulatory
actions, competition and the creditworthiness of our customers.

     Our interstate pipeline systems are also subject to federal, state and
local pipeline safety and environmental statutes and regulations. Our systems
have ongoing programs designed to keep our facilities in compliance with
pipeline safety and environmental requirements, and we believe that our systems
are in material compliance with the applicable requirements.

  Markets and Competition

     We provide natural gas services to a variety of customers including natural
gas producers, marketers, end-users and other natural gas transmission,
distribution and electric generation companies. In performing these services, we
compete with other pipeline service providers as well as alternative energy
sources such as coal, nuclear and hydroelectric power for power generation and
fuel oil for heating.

  Other Matters Impacting Our Markets

     Electric power generation is the fastest growing demand sector of the
natural gas market. The potential consequences of proposed and ongoing
restructuring and deregulation of the electric power industry are currently
unclear. Restructuring and deregulation potentially benefit the natural gas
industry by creating more

                                        4
<PAGE>

demand for natural gas turbine generated electric power, but this effect is
offset, in varying degrees, by increased generation efficiency and more
effective use of surplus electric capacity as a result of open market access. In
addition, in several regions of the country, new capacity additions have
exceeded load growth and transmission capabilities out of those regions. This
may inhibit owners of new power generation facilities from signing firm
contracts with pipelines and may impair their credit worthiness.

     Our existing contracts mature at various times and in varying amounts of
throughput capacity. As our pipeline contracts expire, our ability to extend our
existing contracts or re-market expiring contracted capacity is dependent on the
competitive alternatives, the regulatory environment at the federal, state and
local levels and market supply and demand factors at the relevant dates these
contracts are extended or expire. The duration of new or re-negotiated contracts
will be affected by current prices, competitive conditions and judgments
concerning future market trends and volatility. Subject to regulatory
constraints, we attempt to re-contract or re-market our capacity at the maximum
rates allowed under our tariffs, although we, at times, discount these rates to
remain competitive. The level of discount varies for each of our pipeline
systems.

     The following table details the markets we serve and the competition on
each of our wholly owned pipeline systems as of December 31, 2003:

<Table>
<Caption>
TRANSMISSION
   SYSTEM         CUSTOMER INFORMATION           CONTRACT INFORMATION                      COMPETITION
------------  ----------------------------  -------------------------------  ---------------------------------------
<S>           <C>                           <C>                              <C>
ANR           Approximately 228 firm and    Approximately 537 firm           In the Midwest, ANR competes with other
                interruptible customers     contracts                        interstate and intrastate pipeline
                                            Contracted capacity: 97%         companies and local distribution
                                            Weighted average remaining       companies in the transportation and
                                            contract term of approximately   storage of natural gas. In the
                                            four years.                      Northeast, ANR competes with other
                                                                             interstate pipelines serving electric
              Major Customer:                                                generation and local distribution
                We Energies                                                  companies. ANR also competes directly
                  (1,050 BBtu/d)                                             with other interstate pipelines,
                                            Contract terms expire in         including Guardian Pipeline, for
                                            2004-2010.                       markets in Wisconsin. We Energies owns
                                                                             an interest in Guardian, which is
                                                                             currently serving a portion of its firm
                                                                             transportation requirements.
--------------------------------------------------------------------------------------------------------------------

CIG           Approximately 130 firm and    Approximately 190 firm           CIG serves two major markets. Its
                interruptible customers     contracts                        "on-system" market, consists of
                                            Contracted capacity: 97%         utilities and other customers located
                                            Weighted average remaining       along the front range of the Rocky
                                            contract term of approximately   Mountains in Colorado and Wyoming. Its
              Major Customer:               five years.                      "off-system" market consists of the
                Public Service Company of                                    transportation of Rocky Mountain
                  Colorado                                                   production from multiple supply basins
                  (187 BBtu/d)                                               to interconnections with other
                  (970 BBtu/d)              Contract terms expire in 2005.   pipelines bound for the Midwest, the
                  (261 BBtu/d)              Contract term expires in 2007.   Southwest, California and the Pacific
                                            Contract term expires in         Northwest. Competition for its
                                            2009-2014.                       on-system market consists of local
                                                                             production from the Denver-Julesburg
                                                                             basin, an intrastate pipeline, and
                                                                             long-haul shippers who elect to sell
                                                                             into this market rather than the
                                                                             off-system market. Competition for its
                                                                             off-system market consists of other
                                                                             interstate pipelines that are directly
                                                                             connected to its supply sources and
                                                                             transport these volumes to markets in
                                                                             the West, Northwest, Southwest and
                                                                             Midwest.
</Table>

                                        5
<PAGE>

<Table>
<Caption>
TRANSMISSION
   SYSTEM         CUSTOMER INFORMATION           CONTRACT INFORMATION                      COMPETITION
------------  ----------------------------  -------------------------------  ---------------------------------------
<S>           <C>                           <C>                              <C>

WIC           Approximately 40 firm and     Approximately 50 firm contracts  WIC competes with eight interstate
                interruptible customers     Contracted capacity: 98%         pipelines and one intrastate pipeline
                                            Weighted average remaining       for its mainline supply from several
                                            contract term of approximately   producing basins. WIC's Medicine Bow
                                            six years.                       lateral is the primary source of
                                                                             transportation for increasing volumes
              Major Customers:                                               of Powder River Basin supply and can
                Williams Power Company                                       readily be expanded as supply
                  (303 BBtu/d)              Contract terms expire in         increases. Currently there are two
                Colorado Interstate Gas     2008-2013.                       other interstate pipelines that
                  Company                                                    transport limited volumes out of this
                  (247 BBtu/d)                                               basin.
                Cantera Gas Company         Contract terms expire in
                  (243 BBtu/d)              2004-2007.
                Western Gas Resources
                  (235 BBtu/d)              Contract terms expire in
                                            2004-2013.
                                            Contract terms expire in
                                            2007-2013.
</Table>

PRODUCTION SEGMENT

     Our Production segment is engaged in the exploration for, and the
acquisition, development and production of natural gas, oil and natural gas
liquids, primarily in North America. In the U.S. as of December 31, 2003, we
controlled over 1 million net acres of leasehold through our onshore operations
in 10 states, including Texas, Utah, West Virginia, and Wyoming, and through our
offshore operations in federal and state waters in the Gulf of Mexico. We also
have international exploration and production rights in Australia, Bolivia,
Brazil, Canada, Hungary and Indonesia. During 2003, daily production averaged
approximately 530 MMcfe/d, and our proved natural gas and oil reserves at
December 31, 2003, were approximately 1.1 Tcfe.

     In February 2004, we completed estimates of our December 31, 2003 proved
reserves. The results of this process indicated that a 1.0 Tcfe downward
revision to our proved natural gas and oil reserves was needed. Following an
investigation into the factors that caused this significant revision, we
determined that a material portion of these revisions should be reflected in
prior years and, as a result, we restated our historical proved reserve
estimates and our historical financial information derived from these proved
reserve estimates. See Part II, Item 6, Selected Financial Data and Item 8,
Financial Statements and Supplementary Data, Note 1 for a further discussion of
this restatement.

     As part of El Paso's Long-Range Plan, El Paso will focus on developing
production opportunities from its asset base in the U.S. and Brazil. Based on
this strategy, we will divest our non-core assets, including international
properties in Canada, Hungary and Indonesia. As of September 2004, we have sold
our production operations in Canada and substantially all of our operations in
Indonesia.

     In June 2004, El Paso announced a back-to-basics plan for its Production
businesses. This plan emphasizes strict capital discipline designed to improve
capital efficiency through the use of standardized risk analysis, a heightened
focus on cost control, and a rigorous process for booking proved natural gas and
oil reserves. This back-to-basics approach is designed to stabilize production
by improving the production mix across our operating areas, thereby generating
more predictable income and cash flows in this business.

     Our U.S. operations are divided into the following areas: onshore,
offshore, and coal seam. The onshore area includes operations in two primary
regions: Texas Onshore and Rocky Mountain. The Texas Onshore region includes our
operations along the Texas Gulf Coast and the Rocky Mountain region includes our
interests in Utah. The offshore area includes our interests in the Gulf of
Mexico primarily in state and federal waters along the coast of Texas and
Louisiana. In each of our domestic operating areas, we have extensive acreage
and/or seismic holdings, which allow us to be competitive.

                                        6
<PAGE>

     In Brazil, our operations are concentrated in the Camamu and Santos Basins.
We have been successful with our drilling programs in the Santos and Camamu
Basins and are seeking a strategic partner with a strong interest in Brazil to
contribute near-term development capital in these two basins.

  Natural Gas and Oil Reserves

     The tables below provide information about our proved reserves at December
31, 2003. Reserve information in these tables is based on the reserve report
dated January 1, 2004, prepared internally by us. Ryder Scott Company and
Huddleston & Co., Inc., independent petroleum engineering firms, performed
independent reserve estimates for 84 percent and 16 percent of our properties,
respectively. The total estimate of proved reserves prepared independently by
Ryder Scott Company and Huddleston & Co., Inc. was within five percent of our
internally prepared estimates. This information is consistent with estimates of
reserves filed with other federal agencies except for differences of less than
five percent resulting from actual production, acquisitions, property sales,
necessary reserve revisions and additions to reflect actual experience.

     The table below summarizes our estimated proved reserves as of December 31,
2003, and our 2003 production, by area.

<Table>
<Caption>
                                                           NET PROVED RESERVES(1)
                                              ------------------------------------------------      2003
                                              NATURAL GAS   LIQUIDS(2)           TOTAL           PRODUCTION
                                              -----------   ----------   ---------------------   ----------
                                                (MMCF)       (MBBLS)      (MMCFE)    (PERCENT)    (MMCFE)
<S>                                           <C>           <C>          <C>         <C>         <C>
U.S.
  Onshore
    Texas Onshore...........................    464,351       12,196       537,526       49       122,529
    Central.................................        813            4           839       --           831
    Rocky Mountains.........................     13,016       12,458        87,763        8         6,376
                                                -------       ------     ---------      ---       -------
    Total Onshore...........................    478,180       24,658       626,128       57       129,736
  Offshore..................................    145,798        6,261       183,362       17        46,444
  Coal seam.................................        671            1           678       --           842
                                                -------       ------     ---------      ---       -------
  Total U.S.................................    624,649       30,920       810,168       74       177,022
                                                -------       ------     ---------      ---       -------
International
  Canada(3).................................     97,431        2,986       115,347       11        16,987
  Hungary...................................      4,401           --         4,401       --           401
  Brazil....................................         --       20,543       123,258       11            --
  Indonesia(3)..............................     30,520        1,742        40,972        4            --
                                                -------       ------     ---------      ---       -------
  Total International.......................    132,352       25,271       283,978       26        17,388
                                                -------       ------     ---------      ---       -------
Total.......................................    757,001       56,191     1,094,146      100       194,410
                                                =======       ======     =========      ===       =======
</Table>

---------------
(1) Net proved reserves exclude royalties and interests owned by others
    (including net profits interest) and reflects contractual arrangements and
    royalty obligations at the time of the estimate.
(2) Includes oil, condensate and natural gas liquids.
(3) As of September 2004, we have sold our production operations in Canada and
    substantially all of our operations in Indonesia.

                                        7
<PAGE>

     The table below summarizes our estimated proved producing reserves, proved
non-producing reserves, and proved undeveloped reserves by country as of
December 31, 2003:

<Table>
<Caption>
                                                        NET PROVED RESERVES(1)
                                         ----------------------------------------------------
                                                                                    RELATIVE
                                         NATURAL GAS    LIQUIDS(2)      TOTAL      PERCENTAGE
                                         -----------    ----------    ---------    ----------
                                           (MMCF)        (MBBLS)       (MMCFE)
<S>                                      <C>            <C>           <C>          <C>
U.S.
  Producing............................    393,729        15,712        487,999        60
  Non-Producing........................    108,300         7,424        152,844        19
  Undeveloped..........................    122,620         7,784        169,325        21
                                           -------        ------      ---------       ---
          Total proved.................    624,649        30,920        810,168       100
                                           =======        ======      =========       ===
Canada(3)
  Producing............................     78,944         1,645         88,812        77
  Non-Producing........................      7,835            64          8,218         7
  Undeveloped..........................     10,652         1,277         18,317        16
                                           -------        ------      ---------       ---
          Total proved.................     97,431         2,986        115,347       100
                                           =======        ======      =========       ===
Brazil
  Undeveloped..........................         --        20,543        123,258       100
                                           -------        ------      ---------       ---
          Total proved.................         --        20,543        123,258       100
                                           =======        ======      =========       ===
Other Countries(4)
  Producing............................      4,401            --          4,401        10
  Undeveloped..........................     30,520         1,742         40,972        90
                                           -------        ------      ---------       ---
          Total proved.................     34,921         1,742         45,373       100
                                           =======        ======      =========       ===
</Table>

<Table>
<Caption>
                                                 NET PROVED RESERVES(1)
                                         --------------------------------------     RELATIVE
                                         NATURAL GAS    LIQUIDS(2)      TOTAL      PERCENTAGE
                                         -----------    ----------    ---------    ----------
                                           (MMCF)        (MBBLS)       (MMCFE)
<S>                                      <C>            <C>           <C>          <C>
Worldwide
  Producing............................    477,074        17,357        581,212        53
  Non-Producing........................    116,135         7,488        161,062        15
  Undeveloped..........................    163,792        31,346        351,872        32
                                           -------        ------      ---------       ---
          Total proved.................    757,001        56,191      1,094,146       100
                                           =======        ======      =========       ===
</Table>

---------------
(1) Net proved reserves exclude royalties and interests owned by others
    (including net profits interest) and reflects contractual arrangements and
    royalty obligations in effect at the time of the estimate.
(2) Includes oil, condensate and natural gas liquids.
(3) As of September 2004, we have sold our production operations in Canada.
(4) Includes international operations in Hungary and Indonesia. As of September
    30, 2004, we have sold substantially all of our operations in Indonesia.

     There are considerable uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and the timing of
development expenditures, including many factors beyond our control,
particularly where such reserves are not currently producing or developed. The
reserve data represents only estimates. Reservoir engineering is a subjective
process of estimating underground accumulations of natural gas and oil that
cannot be measured in an exact manner. The accuracy of any reserve estimate is a
function of the quality of available data and of engineering and geological
interpretations and judgment. As a result, estimates of different engineers
often vary. Estimates are subject to revision based upon a number of factors,
including reservoir performance, prices, economic conditions and government
restrictions. In addition, results of drilling, testing and production
subsequent to the date of an estimate may justify revision of that estimate.
Reserve estimates are often different from the quantities of natural gas and oil
that are ultimately recovered. The meaningfulness of reserve estimates is highly
dependent on the accuracy of the assumptions on which they were based. In
general, the volume of production from the natural gas and oil properties we own
declines as reserves are depleted. Except to the extent we conduct successful
exploration and development

                                        8
<PAGE>

drilling or acquire additional properties containing proved reserves, or both,
our proved reserves will decline as reserves are produced.

     In addition, during 2003 we sold reserves totaling approximately 173 Bcfe
to various third parties. The reserves sold were primarily located in New
Mexico, the Gulf of Mexico and western Canada. See Part II, Item 8, Financial
Statements and Supplementary Data, Note 24, for a further discussion of our
reserves.

  Acreage and Wells

     The following table details our gross and net interest in developed and
undeveloped onshore, offshore, coal seam and international lease and mineral
acreage at December 31, 2003. Any acreage in which our interest is limited to
owned royalty, overriding royalty and other similar interests is excluded.

<Table>
<Caption>
                                 DEVELOPED              UNDEVELOPED                TOTAL
                           ---------------------   ---------------------   ---------------------
                           GROSS(1)     NET(2)     GROSS(1)     NET(2)     GROSS(1)     NET(2)
                           ---------   ---------   ---------   ---------   ---------   ---------
                                                         (ACREAGE)
<S>                        <C>         <C>         <C>         <C>         <C>         <C>
U.S.
  Onshore................    730,220     209,410     737,122     499,291   1,467,342     708,701
  Offshore...............    265,908     171,394     189,243     173,777     455,151     345,171
  Coal Seam..............        804         245          --          --         804         245
                           ---------   ---------   ---------   ---------   ---------   ---------
         Total...........    996,932     381,049     926,365     673,068   1,923,297   1,054,117
                           ---------   ---------   ---------   ---------   ---------   ---------
International
  Australia..............         --          --     355,000     177,500     355,000     177,500
  Bolivia................         --          --     154,840      15,484     154,840      15,484
  Brazil(3)..............         --          --   2,137,770   1,468,371   2,137,770   1,468,371
  Canada(4)..............     79,068      61,824     799,250     633,940     878,318     695,764
  Hungary................     77,376      77,376          --          --      77,376      77,376
  Indonesia(4)...........         --          --   1,213,170     378,397   1,213,170     378,397
                           ---------   ---------   ---------   ---------   ---------   ---------
         Total...........    156,444     139,200   4,660,030   2,673,692   4,816,474   2,812,892
                           ---------   ---------   ---------   ---------   ---------   ---------
         Worldwide
           Total.........  1,153,376     520,249   5,586,395   3,346,760   6,739,771   3,867,009
                           =========   =========   =========   =========   =========   =========
</Table>

---------------
(1) Gross interest reflects the total acreage we participated in, regardless of
    our ownership interests in the acreage.
(2) Net interest is the aggregate of the fractional working interest that we
    have in our gross acreage.
(3)In April 2004, we announced the sale of 174,679 gross and net acres
   associated with our Brazilian offshore operations.
(4) As of September 2004, we have sold our production operations in Canada and
    substantially all of our operations in Indonesia.

     The U.S. net developed acreage is concentrated primarily in the Gulf of
Mexico (45 percent), Utah (35 percent), and Texas (18 percent). The domestic net
undeveloped acreage is concentrated primarily in Texas (30 percent), Gulf of
Mexico (26 percent), West Virginia (19 percent) and Wyoming (15 percent).
Approximately 23 percent, 21 percent and 10 percent of our total U.S. net
undeveloped acreage is held under leases that have minimum remaining primary
terms expiring in 2004, 2005 and 2006, respectively. During 2003, we sold
approximately 658,424 net acres primarily located in New Mexico, the Gulf of
Mexico and western Canada.

                                        9
<PAGE>

     The following table details our gross and net interest in productive
onshore, offshore, coal seam and international natural gas and oil wells and the
number of wells being drilled at December 31, 2003:

<Table>
<Caption>
                               PRODUCTIVE            PRODUCTIVE              TOTAL                NUMBER OF
                           NATURAL GAS WELLS         OIL WELLS          PRODUCTIVE WELLS     WELLS BEING DRILLED
                           ------------------    ------------------    ------------------    -------------------
                           GROSS(1)    NET(2)    GROSS(1)    NET(2)    GROSS(1)    NET(2)    GROSS(1)     NET(2)
                           --------    ------    --------    ------    --------    ------    --------     ------
<S>                        <C>         <C>       <C>         <C>       <C>         <C>       <C>          <C>
U.S.
  Onshore................    679        557        270        202         949        759         9           5
  Offshore...............    205        161         35         27         240        188         2           1
  Coal Seam..............     12          3         --         --          12          3        --          --
                             ---        ---        ---        ---       -----      -----        --          --
         Total...........    896        721        305        229       1,201        950        11           6
                             ---        ---        ---        ---       -----      -----        --          --
International
  Canada(3)..............     88         74          7          5          95         79         1           1
  Other..................      1          1         --         --           1          1        --          --
                             ---        ---        ---        ---       -----      -----        --          --
         Total...........     89         75          7          5          96         80         1           1
                             ---        ---        ---        ---       -----      -----        --          --
         Worldwide
           Total.........    985        796        312        234       1,297      1,030        12           7
                             ===        ===        ===        ===       =====      =====        ==          ==
</Table>

------------------
(1) Gross interest reflects the total number of wells we participated in,
    regardless of our ownership interests in the wells.
(2) Net interest is the aggregate of the fractional working interest that we
    have in our gross wells.
(3) As of September 2004, we have sold our production operations in Canada.

     During 2003, we sold approximately 265 net productive wells located
primarily in New Mexico, the Gulf of Mexico and western Canada. At December 31,
2003, we operated 990 of the 1,030 net productive wells.

     The following table details our net exploratory and development wells
drilled for each of the three years ended December 31. As a result of the
restatement of our proved natural gas and oil reserves, some wells drilled that
were previously reported as development wells have been reclassified as
exploratory wells in 2002 and 2001. See Part II, Item 8, Financial Statements
and Supplementary Data, Note 1 for a further discussion of this restatement.

<Table>
<Caption>
                                    NET EXPLORATORY WELLS DRILLED(1)    NET DEVELOPMENT WELLS DRILLED(1)
                                    ---------------------------------   ---------------------------------
                                               2002          2001                  2002          2001
                                    2003    (RESTATED)    (RESTATED)    2003    (RESTATED)    (RESTATED)
                                    -----   -----------   -----------   -----   -----------   -----------
<S>                                 <C>     <C>           <C>           <C>     <C>           <C>
U.S.
  Productive......................   19         18            16          53        166           176
  Dry.............................    9          8             5           1          1            17
                                     --         --            --         ---        ---           ---
    Total.........................   28         26            21          54        167           193
                                     ==         ==            ==         ===        ===           ===
Canada(2)
  Productive......................   10         18            21           3          5            38
  Dry.............................    6         27            35           1          1             3
                                     --         --            --         ---        ---           ---
    Total.........................   16         45            56           4          6            41
                                     ==         ==            ==         ===        ===           ===
Brazil
  Productive......................    3         --            --          --         --            --
  Dry.............................   --         --             5          --         --            --
                                     --         --            --         ---        ---           ---
    Total.........................    3         --             5          --         --            --
                                     ==         ==            ==         ===        ===           ===
Other Countries(3)
  Productive......................   --          1            --          --         --            --
  Dry.............................    1          1             2          --         --            --
                                     --         --            --         ---        ---           ---
    Total.........................    1          2             2          --         --            --
                                     ==         ==            ==         ===        ===           ===
Worldwide
  Productive......................   32         37            37          56        171           214
  Dry.............................   16         36            47           2          2            20
                                     --         --            --         ---        ---           ---
    Total.........................   48         73            84          58        173           234
                                     ==         ==            ==         ===        ===           ===
</Table>

---------------

(1) Net interest is the aggregate of the fractional working interest that we
    have in our gross wells drilled.
(2) As of September 2004, we have sold our production operations in Canada.

(3) Includes international operations in Australia, Hungary and Indonesia. As of
    September 30, 2004, we have sold substantially all of our operations in
    Indonesia.

     The information above should not be considered indicative of future
drilling performance, nor should it be assumed that there is any correlation
between the number of productive wells drilled and the amount of natural gas and
oil that may ultimately be recovered.

                                        10
<PAGE>

  Net Production, Sales Prices, Transportation and Production Costs

     The following table details our net production volumes, average sales
prices received, average transportation costs, average production costs and
average production taxes associated with the sale of natural gas and oil for
each of the three years ended December 31. See our Production segment in Part
II, Item 7, Management's Discussion and Analysis of Financial Condition and
Results of Operations for a further discussion of volumes, prices, and
production costs.

<Table>
<Caption>
                                                               2003      2002      2001
                                                              ------    ------    ------
<S>                                                           <C>       <C>       <C>
Net Production Volumes
  U.S.
    Natural gas (Bcf).......................................     142       247       373
    Oil, condensate and liquids (MMBbls)....................       6         7         8
      Total (Bcfe)..........................................     177       289       422
  Canada(1)
    Natural gas (Bcf).......................................      15        17        13
    Oil, condensate and liquids (MMBbls)....................      --         1         1
      Total (Bcfe)..........................................      17        23        17
  Worldwide
    Natural gas (Bcf).......................................     157       264       386
    Oil, condensate and liquids (MMBbls)....................       6         8         9
      Total (Bcfe)..........................................     194       312       439
Natural Gas Average Sales Price (per Mcf)(2)
  U.S.
    Price, excluding hedges.................................  $ 5.43    $ 3.15    $ 4.23
    Price, including hedges.................................  $ 4.72    $ 4.22    $ 4.09
  Canada(1)
    Price, excluding hedges.................................  $ 4.87    $ 2.85    $ 2.86
    Price, including hedges.................................  $ 4.87    $ 2.84    $ 2.85
  Worldwide
    Price, excluding hedges.................................  $ 5.38    $ 3.09    $ 4.18
    Price, including hedges.................................  $ 4.73    $ 4.14    $ 4.05
Oil, Condensate, and Liquids Average Sales Price (per
  Bbl)(2)
  U.S.
    Price, excluding hedges.................................  $25.25    $20.08    $23.10
    Price, including hedges.................................  $25.25    $20.12    $23.10
  Canada(1)
    Price, excluding hedges.................................  $28.38    $21.56    $17.68
    Price, including hedges.................................  $28.38    $21.55    $18.52
  Worldwide
    Price, excluding hedges.................................  $25.40    $20.28    $22.75
    Price, including hedges.................................  $25.40    $20.31    $22.81
Average Transportation Cost
  U.S.
    Natural gas (per Mcf)...................................  $ 0.15    $ 0.15    $ 0.06
    Oil, condensate, and liquids (per Bbl)..................  $ 0.89    $ 0.66    $ 0.68
  Canada(1)
    Natural gas (per Mcf)...................................  $ 0.86    $ 0.19    $ 0.17
    Oil, condensate, and liquids (per Bbl)..................  $ 0.72    $ 0.39    $ 0.26
  Worldwide
    Natural gas (per Mcf)...................................  $ 0.22    $ 0.16    $ 0.07
    Oil, condensate, and liquids (per Bbl)..................  $ 0.89    $ 0.62    $ 0.65
Average Production Cost (per Mcfe)
  U.S.
    Average lease operating costs...........................  $ 0.47    $ 0.49    $ 0.37
    Average production taxes................................    0.17      0.08      0.16
                                                              ------    ------    ------
      Total production costs(3).............................  $ 0.64    $ 0.57    $ 0.53
                                                              ======    ======    ======
  Canada(1)
    Average production cost(3)..............................  $ 0.48    $ 0.80    $ 0.74
                                                              ======    ======    ======
  Worldwide
    Average lease operating costs...........................  $ 0.47    $ 0.52    $ 0.38
    Average production taxes................................    0.16      0.07      0.15
                                                              ------    ------    ------
      Total production costs(3).............................  $ 0.63    $ 0.59    $ 0.53
                                                              ======    ======    ======
</Table>

---------------
(1) As of September 2004, we have sold our production operations in Canada.
(2) Prices are stated before transportation costs.
(3) Production costs include lease operating costs and production related taxes
    (including ad valorem and severance taxes).

                                        11
<PAGE>

  Acquisition, Development and Exploration Expenditures

     The following table details information regarding the costs incurred in our
acquisition, development and exploration activities for each of the three years
ended December 31, 2003. As a result of the restatement of our proved natural
gas and oil reserves, some costs that were previously reported as development
costs have been reclassified as exploratory drilling costs for the years 2002
and 2001. See Part II, Item 8, Financial Statements and Supplementary Data, Note
1 for a further discussion of this restatement.

<Table>
<Caption>
                                                                       2002          2001
                                                            2003    (RESTATED)    (RESTATED)
                                                            ----    ----------    ----------
                                                                     (IN MILLIONS)
<S>                                                         <C>     <C>           <C>
  U.S.
    Acquisition Costs:
       Proved.............................................  $ --      $   23        $   87
       Unproved...........................................     9          12            33
    Development Costs.....................................   270         569           954
    Exploration Costs:
       Delay rentals......................................     4           4             9
       Seismic acquisition and reprocessing...............     1           2            10
       Drilling...........................................   211         191           163
                                                            ----      ------        ------
         Total............................................  $495      $  801        $1,256
                                                            ====      ======        ======
  Canada(1)
    Acquisition Costs:
       Proved.............................................  $  1      $    6        $  232
       Unproved...........................................    10           7            16
    Development Costs.....................................    57          80           102
    Exploration Costs:
       Seismic acquisition and reprocessing...............     9          21            10
       Drilling...........................................    35          49            12
                                                            ----      ------        ------
         Total............................................  $112      $  163        $  372
                                                            ====      ======        ======
  Brazil
    Acquisition Costs:
       Unproved...........................................  $  4      $    9        $   24
    Exploration Costs:
       Seismic acquisition and reprocessing...............    11          32             6
       Drilling...........................................    84          13            53
                                                            ----      ------        ------
         Total............................................  $ 99      $   54        $   83
                                                            ====      ======        ======
  Other Countries(2)
    Acquisition Costs:
       Unproved...........................................  $ --      $    1        $    2
    Development Costs.....................................     2           2            --
    Exploration Costs:
       Seismic acquisition and reprocessing...............     2           2            --
       Drilling...........................................     9           8            22
                                                            ----      ------        ------
         Total............................................  $ 13      $   13        $   24
                                                            ====      ======        ======
  Worldwide
    Acquisition Costs:
       Proved.............................................  $  1      $   29        $  319
       Unproved...........................................    23          29            75
    Development Costs.....................................   329         651         1,056
    Exploration Costs:
       Delay rentals......................................     4           4             9
       Seismic acquisition and reprocessing...............    23          57            26
       Drilling...........................................   339         261           250
                                                            ----      ------        ------
         Total............................................  $719      $1,031        $1,735
                                                            ====      ======        ======
</Table>

---------------
(1) As of September 2004, we have sold our production operations in Canada.
(2) Includes international operations in Australia, Brazil, Hungary and
    Indonesia. As of September 2004, we have sold substantially all of our
    operations in Indonesia.

                                        12
<PAGE>

     The following table details approximate amounts spent to develop proved
undeveloped reserves that were included in our reserve report for each of the
three years:

<Table>
<Caption>
                                                                     2002          2001
                                                          2003    (RESTATED)    (RESTATED)
                                                          ----    ----------    ----------
                                                                   (IN MILLIONS)
<S>                                                       <C>     <C>           <C>
U.S.....................................................  $50        $88           $23
Canada..................................................   --          3             3
                                                          ---        ---           ---
  Total.................................................  $50        $91           $26
                                                          ===        ===           ===
</Table>

  Regulatory and Operating Environment

     Our natural gas and oil activities are regulated at the federal, state and
local levels, as well as internationally by the countries around the world where
we do business. These regulations include, but are not limited to, the drilling
and spacing of wells, conservation, forced pooling and protection of correlative
rights among interest owners. We are also subject to governmental safety
regulations in the jurisdictions in which we operate.

     Our domestic operations under federal natural gas and oil leases are
regulated by the statutes and regulations of the U.S. Department of the Interior
that currently impose liability upon lessees for the cost of environmental
impacts resulting from their operations. Royalty obligations on all federal
leases are regulated by the Minerals Management Service, which has promulgated
valuation guidelines for the payment of royalties by producers. Our
international operations are subject to environmental regulations administered
by foreign governments, which include political subdivisions and international
organizations. These domestic and international laws and regulations relating to
the protection of the environment affect our natural gas and oil operations
through their effect on the construction and operation of facilities, drilling
operations, production or the delay or prevention of future offshore lease
sales. We believe that our operations are in material compliance with the
applicable requirements. In addition, we maintain insurance on our production
business for sudden and accidental spills and oil pollution liability.

     Our production business has operating risks normally associated with the
exploration for and production of natural gas and oil, including blowouts,
cratering, pollution and fires, each of which could result in damage to life or
property. In addition, offshore operations may encounter usual marine perils,
including hurricanes and other adverse weather conditions, damage from
collisions with vessels, governmental regulations and interruption or
termination by governmental authorities based on environmental and other
considerations. Customary with industry practices, El Paso maintains insurance
coverage on our behalf with respect to potential losses resulting from these
operating hazards.

  Markets and Competition

     We primarily sell our natural gas and oil to third parties through El Paso
Merchant Energy L.P. (El Paso Merchant Energy), a wholly owned subsidiary of El
Paso, at spot market prices, subject to customary adjustments. We sell our
natural gas liquids at market prices under monthly or long-term contracts,
subject to customary adjustments. We also engage in hedging activities with El
Paso Merchant Energy on a portion of our natural gas and oil production to
stabilize our cash flows and reduce the risk of downward commodity price
movements on sales of our production.

     The natural gas and oil business is highly competitive in the search for
and acquisition of additional reserves and in the sale of natural gas, oil and
natural gas liquids. Our competitors include major and intermediate sized
natural gas and oil companies, independent natural gas and oil operators and
individual producers or operators with varying scopes of operations and
financial resources. Competitive factors include price and contract terms.
Ultimately, our future success in the production business will be dependent on
our ability to find or acquire additional reserves at costs that allow us to
remain competitive.

                                        13
<PAGE>

FIELD SERVICES SEGMENT

     Our Field Services segment conducts our midstream activities which includes
gathering and processing of natural gas. For the majority of 2003, our assets
principally consisted of our consolidated processing assets in south Louisiana.

 Processing and Gathering Operations

     Our processing and gathering operations provide processing and gathering
services to natural gas producers, primarily in the south Louisiana production
area. The following tables provide information regarding the operational
capacity and volumes of these processing and gathering facilities:

<Table>
<Caption>
                                INLET
                              CAPACITY            AVERAGE INLET          AVERAGE NATURAL
                          -----------------          VOLUME             GAS LIQUIDS SALES
                            DECEMBER 31,      ---------------------   ---------------------
   PROCESSING PLANTS            2003          2003    2002    2001    2003    2002    2001
   -----------------      -----------------   -----   -----   -----   -----   -----   -----
                              (MMcfe/d)             (BBtue/d)               (Mgal/d)
<S>                       <C>                 <C>     <C>     <C>     <C>     <C>     <C>
South Louisiana.........        2,550         1,627   1,407   1,712   1,726   1,604   1,619
Other areas.............           49            60     347     254     139     739     976
                                -----         -----   -----   -----   -----   -----   -----
  Total.................        2,599         1,687   1,754   1,966   1,865   2,343   2,595
                                =====         =====   =====   =====   =====   =====   =====
</Table>

<Table>
<Caption>
                                               DECEMBER 31, 2003              AVERAGE
                                           -------------------------         THROUGHPUT
                                            MILES OF     THROUGHPUT     --------------------
                GATHERING                   PIPELINE      CAPACITY      2003    2002    2001
                ---------                  -----------   -----------    ----    ----    ----
                                                          (MMcfe/d)          (BBtue/d)
<S>                                        <C>           <C>            <C>     <C>     <C>
Other areas..............................      852           211        101     628     843
</Table>

  Regulatory Environment

     We are subject to the Natural Gas Pipeline Safety Act of 1968, the
Hazardous Liquid Pipeline Safety Act of 1979 and various environmental statutes
and regulations. Each of our pipelines has continuing programs designed to keep
the facilities in compliance with pipeline safety and environmental
requirements, and we believe that these systems are in material compliance with
the applicable requirements.

  Markets and Competition

     We compete with major interstate and intrastate pipeline companies in
transporting natural gas and NGL's. We also compete with major integrated energy
companies, independent natural gas gathering and processing companies, natural
gas marketers and oil and natural gas producers in gathering and processing
natural gas and NGL's. Competition for throughput and natural gas supplies is
based on a number or factors, including price, efficiency of facilities,
gathering system line pressures, availability of facilities near drilling
activity, service and access to favorable downstream markets.

MERCHANT ENERGY SEGMENT

     Our Merchant Energy segment includes the ownership and operation of
domestic and international power generation facilities as well as the management
of restructured power contracts. As of December 31, 2003, we owned or had
interests in 19 power plants in 8 countries with a total generating capacity of
4,281 gross MW. Our commercial focus has historically been either to develop
projects in which new long-term power purchase agreements allow for an
acceptable return on capital, or to acquire projects with existing above-market
power purchase agreements. El Paso's Board of Directors authorized a plan in
December 2003 that included the sale of four of our six domestic power
generation plants. As of September 2004, we have sold two plants with a total
generating capacity of 582 gross MW. See Part II, Item 8, Financial Statements
and Supplementary Data, Note 4. El Paso continues to seek opportunities to sell
or otherwise divest of our remaining domestic power plants and our international
assets.

                                        14
<PAGE>

     As of December 31, 2003, we owned or had direct investment interests in the
following power plants:

<Table>
<Caption>
                                                                                                   EXPIRATION
                                                                                                    YEAR OF
                                                EL PASO CGP                                          POWER
                                                 OWNERSHIP     GROSS              POWER              SALES
PROJECT                         COUNTRY          INTEREST     CAPACITY          PURCHASER          CONTRACTS    FUEL TYPE
-------                         -------         -----------   --------          ---------          ----------   ---------
                                                 (PERCENT)      (MW)
<S>                        <C>                  <C>           <C>        <C>                       <C>         <C>
DOMESTIC
 Midland(1)                U.S.                      44        1,575     Consumers Power & Dow        2025     Natural Gas
 CDECCA(3)                 U.S.                     100           62     --(2)                       --(2)     Natural Gas
 Fulton(3)(4)              U.S.                     100           48     --(2)                       --(2)     Natural Gas
 Rensselaer(3)             U.S.                     100           86     --(2)                       --(2)     Natural Gas
 Bastrop(1)(3)(4)          U.S.                      50          534     --(2)                       --(2)     Natural Gas
 Eagle Point(5)            U.S.                     100          233     --(2)                       --(2)     Natural Gas
CENTRAL AMERICA
 CEPP(1)                   Dominican Republic        48           67     CDEEE                        2014     Oil
 Fortuna(1)                Panama                    25          300     Union Fenosa              2004, 2005  Hydroelectric
 GEOSA(1)                  Nicaragua                 26          115     Union Fenosa              2005, 2008  Oil
 Itabo(1)                  Dominican Republic        25          416     CDEEE                        2016     Oil/Coal
 Nejapa                    El Salvador               87          144     AES & PPL                 2004, 2005  Oil
 Pedregal(1)               Panama                    21           50     Union Fenosa                 2005     Oil
 Tipitapa(1)               Nicaragua                 60           51     Union Fenosa                 2014     Oil
ASIA
 Habibullah(1)             Pakistan                  50          136     Pakistan Water and Power     2029     Natural Gas
 Khulna(1)                 Bangladesh                74          113     Bangladesh Power             2013     Oil
 Nanjing(1)                China                     80           75     Jiangsu Power                2017     Diesel
 Saba(1)                   Pakistan                  94          128     Pakistan Water and Power     2029     Oil
 Suzhou(1)                 China                     60          109     Jiangsu Power                2016     Diesel
 Wuxi(1)                   China                     60           39     Jiangsu Power                2010     Diesel
</Table>

---------------

(1) These power facilities are reflected as investments in unconsolidated
    affiliates in our financial statements.
(2) These power facilities (referred to as merchant plants) do not have
    long-term power purchase agreements and, as a result, sell the power they
    generate into the wholesale power market.
(3) In December 2003, El Paso's Board approved a plan for selling these power
    facilities.
(4) We completed the sale of these assets in 2004.
(5) This power facility is currently being leased to a third party who has an
    option to purchase in 2005.

     In addition to our power plants above, we were involved in activities in
2001 and 2002 that we have referred to as our power restructuring business.
These activities involved restructuring above-market, long-term power purchase
agreements with utilities that were originally tied to older power plants built
under the Public Utility Regulatory Policies Act of 1978 (PURPA). These PURPA
facilities were typically less efficient and more costly than newer power
generation facilities. Our power restructuring activities included restructuring
the contracts held by our consolidated Eagle Point and CDECCA power facilities.
In the restructuring, the contracts were amended so that the power sold to the
utilities did not have to be provided from the specific power plant, but could
be obtained in the wholesale power market. While we are no longer actively
seeking to restructure additional power purchase contracts, we continue to
manage the physical purchase and sale of electricity as required under the
restructured power contracts. As of December 31, 2003, our only significant
remaining restructured power contract is held by our wholly owned subsidiary,
Utility Contract Funding, L.L.C. (UCF). Morgan Stanley supplies the fuel under
this contract and PSEG is obligated to purchase a minimum annual volume of 1,666
MMwh under this contract through 2016. We sold our interest in UCF in June 2004.

 Regulatory Environment

     Our domestic power generation activities are regulated by the FERC under
the Federal Power Act with respect to the rates, terms and conditions of service
of these regulated plants. In addition, exports of electricity outside of the
U.S. must be approved by the Department of Energy. Our cogeneration power
production activities are regulated by the FERC under PURPA with respect to
rates, procurement and provision of services and operating standards. Our power
generation activities are also subject to federal, state and local environmental
regulations.

                                        15
<PAGE>

     Our international power generation activities are regulated by numerous
governmental agencies in the countries in which these projects are located. Many
of the countries in which we conduct business have recently developed or are
developing new regulatory and legal structures to accommodate private and
foreign-owned businesses. These regulatory and legal structures and their
interpretation and application by administrative agencies are relatively new,
are sometimes limited and are at risk to change, which may affect our
contractual arrangements. Many detailed rules and procedures are yet to be
issued, and we expect that the interpretation and modification of existing rules
in these jurisdictions will evolve over time.

  Markets and Competition

     The domestic power generation industry continues to evolve and regulatory
initiatives have been adopted at the federal and state level aimed at increasing
competition in the power generation business. As a result, our domestic
facilities are required to compete in the marketplace in which operating
efficiency and other economic factors will determine success. We are likely to
face intense competition from generation companies as well as from the wholesale
power markets.

     Many of our international power generation facilities sell power under
long-term power purchase agreements primarily with power transmission and
distribution companies owned by the local governments where the facilities are
located. When these long-term contracts expire, these facilities will be subject
to regional market and competitive risks.

DISCONTINUED OPERATIONS

     Our discontinued operations consist of our petroleum markets and coal
mining businesses.

     Petroleum Markets.  In 2003, El Paso announced its intent to sell our
petroleum markets business since it was not core to El Paso's primary natural
gas business. During 2003 and 2004, El Paso sold substantially all of our
petroleum markets assets. As of December 31, 2003, our petroleum markets
business owned or had interests in two crude oil refineries and two chemical
production facilities and had petroleum terminalling and related marketing
operations. Our refineries operated at 74 percent of their combined daily
capacity in 2003, at 66 percent in 2002 and at 71 percent in 2001. The aggregate
sales volumes at our wholly owned refineries were approximately 118 MMBbls in
2003, 110 MMBbls in 2002 and 131 MMBbls in 2001. Of our total refinery sales in
2003, 24 percent was gasoline, 38 percent was middle distillates, such as jet
fuel, diesel fuel and home heating oil, and 38 percent was heavy industrial
fuels and other products. The following table presents information on our
wholly-owned refineries as of and for the years ended December 31:

<Table>
<Caption>
                                                                          AS OF DECEMBER 31,
                                                      AVERAGE DAILY              2003
                                                        THROUGHPUT       --------------------
                                                    ------------------    DAILY      STORAGE
REFINERY                      LOCATION              2003   2002   2001   CAPACITY    CAPACITY
--------                      --------              ----   ----   ----   --------    --------
                                                                   (IN MBBLS)
<S>               <C>                               <C>    <C>    <C>    <C>         <C>
Aruba(1)          Aruba...........................  173    146    178      280        14,652
Eagle Point(2)    Westville, New Jersey...........  140    127    118      150         8,492
Mobile(3)         Mobile, Alabama.................    6      9     10       --            --
                                                    ---    ---    ---      ---        ------
     Total........................................  319    282    306      430        23,144
                                                    ===    ===    ===      ===        ======
</Table>

---------------

(1) In March 2004, we completed the sale of our Aruba refinery to Valero Energy
    Corporation.
(2) In January 2004, we completed the sale of our Eagle Point refinery to Sunoco
    Corporation.
(3) In July 2003, we sold our Mobile refinery to Trigeant EP, Ltd. These volumes
    only reflect those produced prior to the sale of the refinery.

                                        16
<PAGE>

     Our chemical plants produce gasoline additives and paraxylene at our
facilities in Wyoming and Montreal. The following table provides information on
sales volumes from our wholly owned chemical facilities in the U.S. for each of
the three years ended December 31:

<Table>
<Caption>
                                                              2003   2002    2001
                                                              ----   -----   -----
                                                                    (MTONS)
<S>                                                           <C>    <C>     <C>
Industrial(1)...............................................  417      512     492
Agricultural(1).............................................  352      380     378
Gasoline additives(2).......................................  139      199     173
                                                              ---    -----   -----
          Total.............................................  908    1,091   1,043
                                                              ===    =====   =====
</Table>

---------------

(1) In December 2003, we sold our chemical facilities that produced
    nitrogen-based industrial and agricultural products to Dyno Nobel, Inc. We
    expect to sell our remaining chemical facilities in 2004.

(2) Removed from service in October 2003.

     Our petroleum markets business is subject to federal, state and local
environmental regulations and its customers are principally independent energy
marketers and retailers.

     Coal Mining.  Prior to its discontinuance in 2002, our coal mining business
controlled reserves totaling 524 million recoverable tons and produced
high-quality bituminous coal from reserves in Kentucky, Virginia and West
Virginia. The extracted coal was primarily sold under long-term contracts to
power generation facilities in the eastern U.S. During late 2002 and early 2003,
these operations were sold.

                                 ENVIRONMENTAL

     A description of our environmental activities is included in Part II, Item
8, Financial Statements and Supplementary Data, Note 18, and is incorporated
herein by reference.

                                   EMPLOYEES

     As of September 24, 2004, we had approximately 856 full-time employees,
none of whom are subject to collective bargaining agreements.

                                        17
<PAGE>

                      EXECUTIVE OFFICERS OF THE REGISTRANT

     Our executive officers as of October 11, 2004, are listed below. Prior to
August 1, 1998, all references to El Paso refer to positions held with El Paso
Natural Gas Company.

<Table>
<Caption>
                                                                                  OFFICER
         NAME                                    OFFICE                            SINCE    AGE
         ----                                    ------                           -------   ---
<S>                      <C>                                                      <C>       <C>
Douglas L. Foshee......  Chairman of the Board, President and Chief Executive
                         Officer                                                    2003     45
D. Dwight Scott........  Executive Vice President and Chief Financial Officer
                         and Director                                               2002     41
Robert W. Baker........  Executive Vice President, General Counsel and Director     1996     48
</Table>

     Douglas L. Foshee has served as our Chairman of the Board, President and
CEO since January 2004. Mr. Foshee has been President, Chief Executive Officer,
and a Director of El Paso since September 2003. Mr. Foshee became Executive Vice
President and Chief Operating Officer of Halliburton Company in 2003, having
joined that company in 2001 as Executive Vice President and Chief Financial
Officer. In December 2003, several subsidiaries of Halliburton, including DII
Industries and Kellogg Brown & Root, filed for bankruptcy protection whereby the
subsidiaries will jointly resolve their asbestos claims. Prior to that, Mr.
Foshee was President, Chief Executive Officer, and Chairman of the Board at
Nuevo Energy Company. From 1993 to 1997, Mr. Foshee served Torch Energy Advisors
Inc. in various capacities, including Chief Operating Officer and Chief
Executive Officer. He held various positions in finance and new business
ventures with ARCO International Oil and Gas Company and spent seven years in
commercial banking, primarily as an energy lender.

     D. Dwight Scott has served as our Executive Vice President, Chief Financial
Officer and as a Director since January 2004. Mr. Scott has been Executive Vice
President and Chief Financial Officer of El Paso since October 2002. Mr. Scott
served as Senior Vice President of Finance and Planning for El Paso from July
2002 to September 2002. Mr. Scott was Executive Vice President of Power for El
Paso Merchant Energy from December 2001 to June 2002, and he served as Chief
Financial Officer of El Paso Global Networks from October 2000 to November 2001.
From January 1999 to October 2000, he served as a managing director in the
energy investment banking practice of Donaldson, Lufkin and Jenrette.

     Robert W. Baker has served as our Executive Vice President and General
Counsel since January 2004 and as a Director since April 2004. Mr. Baker has
been Executive Vice President and General Counsel of El Paso since January 2004.
From February 2003 to December 2003, he served as Executive Vice President of El
Paso and President of El Paso Merchant Energy. He was Senior Vice President and
Deputy General Counsel of El Paso from January 2002 to February 2003. Prior to
that time he held various positions in the legal department of Tenneco Energy
and El Paso since 1983.

                                        18
<PAGE>

ITEM 2. PROPERTIES

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

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

ITEM 3. LEGAL PROCEEDINGS

     A description of our legal proceedings are included in Part II, Item 8,
Financial Statements and Supplementary Data, Note 18, and is incorporated herein
by reference.

     Following is a description of certain environmental proceedings to which a
governmental authority is a party and potential monetary sanctions are $100,000
or more.

     Corpus Christi Refinery Air Violations.  On March 18, 2004, the Texas
Commission on Environmental Quality (TCEQ) issued an "Executive Director's
Preliminary Report and Petition" seeking $645,477 in penalties relating to air
violations alleged to have occurred at our former Corpus Christi, Texas refinery
from 1996 to 2000. We have filed a hearing request to protect our procedural
rights and have initiated negotiations with the TCEQ.

     Coastal Eagle Point.  The Coastal Eagle Point Oil Company received several
Administrative Orders and Notices of Civil Administrative Penalty Assessment
from the New Jersey Department of Environmental Protection (DEP). The Orders
alleged noncompliance with the New Jersey Air Pollution Control Act, primarily
pertaining to excess emissions reported since 1998 by the Eagle Point refinery
in Westville, New Jersey. On February 24, 2003, the Environmental Protection
Agency (EPA) Region 2 issued a Compliance Order based on a 1999 EPA inspection
of the refinery's leak detection and repair (LDAR) program. Alleged violations
include a failure to monitor all components and failure to timely repair leaking
components. The Eagle Point refinery resolved the claims of the U.S. and the
State of New Jersey in a Consent Decree on September 30, 2003, pursuant to the
EPA's refinery enforcement initiative. The Consent Decree was entered on
December 2, 2003. We paid a civil penalty of $1.25 million to the U.S. and $1.25
million to New Jersey. We contributed $1.0 million to an environmentally
beneficial project near the refinery. The Eagle Point refinery will invest an
estimated $3 to $7 million to upgrade the plant's environmental controls by
2008. The Eagle Point Refinery was sold in January 2004. We will share certain
future costs associated with implementation of the Consent Decree pursuant to
the Purchase and Sale Agreement. On April 1, 2004, the DEP issued an
Administrative Order and Notice of Civil Administrative Penalty Assessment
seeking $183,000 in penalties for excess emission events that occurred during
the fourth quarter of 2003 at the refinery, prior to the sale. We are reviewing
the information behind the excess emission events and have filed an
administrative appeal contesting the penalty.

     St. Helens.  On November 11, 2003, our St. Helens, Oregon chemical plant
discovered a release of ammonia at the facility and reported the release to the
National Response Center and state and local contacts on November 12, 2003. The
EPA has alleged violations of the Comprehensive Environmental Response,
Compensation and Liability Act (CERCLA) and the Emergency Planning and Community
Right-to-Know Act (EPCRA) reporting requirements associated with the reporting
of the release. On December 3, 2003, the St. Helens plant was sold to Dyno
Nobel, Inc. On April 21, 2004, the EPA issued a demand to El Paso Merchant
Energy -- Petroleum Company for penalties for the alleged violations. We
responded to the EPA demand, and we have resolved the alleged violations by
agreeing to a penalty of $50,345 and by agreeing to conduct a supplemental
project costing $59,581.

     Natural Buttes.  On May 19, 2003, we met with the EPA to discuss potential
"prevention of significant deterioration" violations due to a de-bottlenecking
modification at Colorado Interstate Gas Company's facility. The EPA issued an
Administrative Compliance Order and we are in negotiations with the EPA as to
the appropriate penalty.

                                        19
<PAGE>

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

     None.

                                    PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

     All of our common stock, par value $1 per share, is owned by El Paso and,
accordingly, our common stock is not publicly traded.

ITEM 6. SELECTED FINANCIAL DATA

     The information for the years from 1999 until 2002 and for the first nine
months of 2003 has been restated. For a further discussion of the restatement
and the 2003, 2002 and 2001 restatement amounts, see Item 8, Financial
Statements and Supplementary Data, Note 1. See the notes to the table below for
the impact of this restatement on 2000 and 1999. The following historical
selected financial data excludes our petroleum markets and coal mining
businesses, which are presented as discontinued operations in our financial
statements for all periods. The selected financial data below should be read
together with Item 7, Management's Discussion and Analysis of Financial
Condition and Results of Operations and Item 8, Financial Statements and
Supplementary Data included in this Annual Report on Form 10-K. These selected
historical results are not necessarily indicative of results to be expected in
the future.

<Table>
<Caption>
                                                                   YEAR ENDED DECEMBER 31,
                                             --------------------------------------------------------------------
                                                         2002          2001            2000             1999
                                              2003    RESTATED(1)   RESTATED(1)   RESTATED(1)(2)   RESTATED(1)(2)
                                             ------   -----------   -----------   --------------   --------------
                                                                        (IN MILLIONS)
<S>                                          <C>      <C>           <C>           <C>              <C>
Operating Results Data:
  Operating revenues.......................  $2,374     $3,826        $3,964          $3,533           $2,334
  Merger-related costs(3)..................      --         --           787              13               --
  Depreciation, depletion and
     amortization..........................     517        630           836             601              390
  Ceiling test charges.....................     109        521           537              --              152
  Loss (gain) on long-lived assets.........      97         (7)           69              (1)              --
  Operating income (loss)..................     520        777          (346)            895              484
  Income taxes (benefit)...................     (57)       109           (87)            220               99
  Income (loss) from continuing
     operations............................     175        316          (493)            520              388
</Table>


<Table>
<Caption>
                                                                    AS OF DECEMBER 31,
                                           ---------------------------------------------------------------------
                                                        2002          2001            2000             1999
                                            2003     RESTATED(1)   RESTATED(1)   RESTATED(1)(2)   RESTATED(1)(2)
                                           -------   -----------   -----------   --------------   --------------
                                                                       (IN MILLIONS)
<S>                                        <C>       <C>           <C>           <C>              <C>
Financial Position Data:
  Total assets...........................  $12,409     $15,555       $16,768         $17,185          $13,334
  Long-term debt.........................    5,011       4,985         5,056           5,600            3,305
  Stockholder's equity...................    3,345       3,352         3,498           3,477            2,875
</Table>

                                        20
<PAGE>

---------------

(1) In February 2004, we completed an assessment of our December 31, 2003 proved
    natural gas and oil reserve estimates. The assessment indicated a downward
    revision to our proved reserve estimates of 1.0 Tcfe was needed. Upon
    completion of an investigation into the factors that caused this revision,
    we determined that a material portion of the revision should be reflected in
    all of the historical periods included in this Annual Report on Form 10-K.
    As a result, we restated our historical financial statements for all periods
    to reflect the impacts of the revised reserve estimates on the financial
    statement amounts. The cumulative impact of the restatement on total
    stockholder's equity as of September 30, 2003 (the most recent balance sheet
    filed) was a reduction of approximately $1.1 billion, which includes the
    reduction to beginning stockholder's equity as of January 1, 2001 of
    approximately $1.1 billion. See Item 8, Financial Statements and
    Supplementary Data, Note 1, for a further discussion of our restatement
    process as well as the financial impacts of the restatement on 2001, 2002
    and 2003. The financial impacts on 1999 and 2000 of the restatement were as
    follows:

<Table>
<Caption>
                                                                      2000                  1999
                                                               -------------------   -------------------
                                                               REPORTED   RESTATED   REPORTED   RESTATED
                                                               --------   --------   --------   --------
                                                                             (IN MILLIONS)
<S>                                                            <C>        <C>        <C>        <C>
Income from continuing operations...........................   $   531    $   520    $   468    $   388
Total assets................................................    18,875     17,185     15,123     13,334
Stockholder's equity........................................     4,550      3,477      3,937      2,875
</Table>

    The restated stockholder's equity at December 31, 1999 includes a decrease
    in 1999 income of $80 million, net of tax, due to an increased ceiling test
    charge, partially offset by lower depletion expense, as well as a reduction
    to beginning retained earnings of $1 billion for charges that would have
    occurred in periods prior to January 1, 1999 as a result of our revised
    reserve levels. As discussed in Item 8, Financial Statements and
    Supplementary Data, Note 1, we revised our reserves for the periods from
    December 31, 2000 to September 30, 2003 using a reserve reconstruction
    approach. For each quarter from December 31, 1998 through the third quarter
    of 2000, we estimated reserves using an approach that involved the use of a
    "reserve over production ratio" based on the reconstructed December 31, 2000
    reserve estimates. The reserve over production ratio provided the estimated
    life of reserves based on production levels. We applied that ratio to the
    actual historical period production levels to calculate estimated historical
    reserves for each period. In determining the reserve over production ratio
    to use for each period, historical prices at the end of each quarter were
    considered, since at different pricing levels, more or less reserves are
    economical to produce, which also impacts capital cost, operating cost and
    revenue assumptions in determining cash flows that will be derived from
    reserves. These overall quarterly reserve levels were then used to
    recalculate the associated net future cash flows for each quarter during
    those periods. Ceiling test charges and depreciation, depletion and
    amortization rates were then determined based on these restated estimated
    reserve levels and related net future cash flows. Finally, we assessed the
    reasonableness of our initial adjustment as of December 31, 1998 based on
    historical prices and our historical capitalized costs prior to that time.
    Based on that assessment, we believe the amount recorded as a retained
    earnings adjustment on January 1, 1999 reasonably reflects the financial
    statement impact of our restated reserve levels that would have occurred
    prior to that time. We believe the approach used to reconstruct our
    historical reserve estimates was reasonable in light of the information
    available to us and the circumstances surrounding our restatement. See Item
    8, Financial Statements and Supplementary Data, Note 1, for a further
    discussion of the methodologies used to restate our natural gas and oil
    reserves and the reasons for the differences in the methods used in
    computing our restated reserves.

    The "as reported" income from continuing operations differs from those
    amounts originally included in our 2000 Form 10-K by $123 million for 2000
    and $31 million for 1999 due to reclassifications associated with our
    discontinued operations and other minor reclassifications which had no
    impact on previously reported net income.

(2) The impacts of the historical restatements for the years ended December 31,
    2000 and 1999 have not been audited.

(3) During 2001, we merged with El Paso Corporation and incurred employee,
    business and integration costs related to this merger.

                                        21
<PAGE>

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

     Our Management's Discussion and Analysis includes forward-looking
statements that are subject to risks and uncertainties. Actual results may
differ substantially from the statements we make in this section due to a number
of factors that are discussed beginning on page 46. The historical financial
information in this section has been restated as further discussed in Item 8,
Financial Statements and Supplementary Data, Note 1. The information contained
in this discussion also presents our petroleum markets and our coal mining
businesses as discontinued operations for all periods.

                        LIQUIDITY AND CAPITAL RESOURCES

LIQUIDITY

     We rely on cash generated from our internal operations and loans from El
Paso through its cash management program as our primary sources of liquidity, as
well as asset sales and capital contributions from El Paso. We expect that our
future funding for working capital needs, capital expenditures and debt service
will continue to be provided from some or all of these sources. Each of these
sources is impacted by factors that influence the overall amount of cash
generated by us and the capital available to us. For example, cash generated by
our business operations may be impacted by changes in commodity prices or
demands for our commodities or services due to weather patterns, competition
from other providers or alternative energy sources. Cash generated by future
asset sales may depend on the overall economic conditions of the industries
served by these assets, the condition and location of the assets and the number
of interested buyers.

     El Paso is a significant source of liquidity to us, and we participate in
its cash management program. Under this program, depending on whether we have
short-term cash surpluses or requirements, we either provide cash to El Paso or
El Paso provides cash to us. We have historically and consistently borrowed cash
from El Paso under this program. Currently, one of our subsidiaries, CIG, is not
advancing funds to El Paso via the cash management program based on its expected
cash needs. On December 31, 2003, El Paso authorized a capital contribution of
$1.5 billion to us and as of December 31, 2003, we had a note payable to El Paso
of $906 million related to this program. This note is classified as a current
liability in our balance sheet because it is due upon demand. Our ability to
rely on advances from El Paso can be impacted by its credit standing, its
requirement to repay debt and other financing obligations, and the cash demands
from other parts of its business. If El Paso were unable to meet its liquidity
needs, we would not have access to this source of liquidity. Furthermore, we
would be required to repay affiliated company payables, if demanded. However, we
do not anticipate that El Paso will require us to repay these payables during
2004.

     In February 2004, El Paso completed the December 31, 2003 reserve
estimation process for its proved natural gas and oil reserves which included
reserves in our Production segment. As a result of this review, El Paso
announced that it was significantly reducing its proved natural gas and oil
reserve estimates, including our estimates. Following the conclusion of an
independent investigation into this matter, El Paso announced that a restatement
of its historical financial statements, as well as ours, was required.

     El Paso believes that a material restatement of its financial statements
would have constituted events of default under its $3 billion revolving credit
facility and various other financing transactions, specifically under the
provisions related to representations and warranties on the accuracy of its
historical financial statements and on El Paso's debt to capitalization ratio.
During 2004, El Paso received several waivers on its $3 billion revolving credit
facility and various other financing transaction to address the restatement.
These waivers continue to be effective. El Paso also received an extension of
time with various lenders until November 30, 2004 to file its first and second
quarter 2004 Forms 10-Q, which it expects to meet. If El Paso is unable to file
its Forms 10-Q by that date and it is not able to negotiate an additional
extension of the filing deadline, the $3 billion revolving credit facility and
various other financing transactions could be accelerated. As part of obtaining
its waivers, El Paso also amended various provisions of the $3 billion revolving
credit facility, including provisions related to events of default, and
limitations on the ability of El Paso and its subsidiaries to repay indebtedness
scheduled to mature after June 30, 2005. Although two of our subsidiaries

                                        22
<PAGE>

(ANR and CIG) are eligible to borrow under El Paso's $3 billion revolving credit
facility, they do not have any borrowings or letters of credit outstanding under
that facility. Based upon a review of the provisions of our indentures and the
financing agreements, we believe that a default on El Paso's $3 billion
revolving credit facility would not result in an event of default under our
other debt agreements unless such default resulted in the acceleration of El
Paso's $3 billion revolving credit facility or other transactions collateralized
by the same assets, and our subsidiaries failed to perform their obligations
under their guarantees of such debt.

     Various other financing arrangements entered into by El Paso and its
subsidiaries, including us, include covenants that require us to file financial
statements within specified time periods. Non-compliance with these covenants
does not constitute an automatic event of default. Instead, such agreements are
subject to acceleration when the indenture trustee or the holders of at least 25
percent of the outstanding principal amount of any series of debt provides
notice to the issuer of non-compliance under the indenture. In that event, the
default can be cured by filing financial statements within specified periods of
time (between 30 and 90 days after receipt of notice depending on the particular
indenture) to avoid acceleration of repayment. The filing of our first and
second quarter 2004 Forms 10-Q will cure the events of non-compliance resulting
from our failure to file financial statements. We have not received a notice of
the default caused by our failure to file our financial statements. In the event
of an acceleration, we may be unable to meet our payment obligations with
respect to the related indebtedness.

     If El Paso were subject to voluntary or involuntary bankruptcy proceedings,
El Paso and its other subsidiaries and their creditors could attempt to make
claims against us, including claims to substantively consolidate our assets and
liabilities with those of El Paso and its other subsidiaries. We believe that
claims to substantively consolidate us with El Paso and/or its other
subsidiaries would be without merit. However, there is no assurance that El Paso
and/or its other subsidiaries or their creditors would not advance such a claim
in a bankruptcy proceeding. If we were to be substantively consolidated in a
bankruptcy proceeding with El Paso and/or its other subsidiaries, there could be
a material adverse effect on our financial condition and our liquidity.

     Some of our subsidiaries are subsidiary guarantors of El Paso's $3 billion
revolving credit facility and other financing transactions. In connection with
their guarantees, El Paso pledged our ownership of ANR, ANR Storage, CIG, and
WIC to collateralize the $3 billion revolving credit facility and approximately
$300 million of other financing arrangements including leases, letters of credit
and other facilities. Our ownership in the above mentioned companies is subject
to change if El Paso's lenders under these facilities exercise their rights over
the collateral. If this were to occur, it could have a material adverse effect
on our financial condition. In addition, one of our subsidiaries has pledged as
collateral a portion of its natural gas and oil properties to support the
obligations of some of our affiliates to make payments in connection with the
settlement of various lawsuits arising out of the Western Energy Crisis. If our
affiliates fail to make those payments, the properties that our subsidiary has
pledged would be subject to foreclosure, which could have a material adverse
effect on our financial position, results of operations and cash flows.

     We have cross-acceleration provisions in our long-term debt-agreements
which, if triggered, could result in the acceleration of our debt. The most
restrictive indenture has a cross-acceleration threshold of $5 million. The
acceleration of our long-term debt would adversely affect our liquidity position
and, in turn, our financial condition.

     We believe we will generate sufficient funds through our operations, asset
sales, financing activities and advances from El Paso to meet all of our cash
needs.

                                        23
<PAGE>

  Overview of Cash Flow Activities

     For the years ended December 31, 2003 and 2002 our cash flows from
continuing operations are summarized as follows:

<Table>
<Caption>
                                                                            2002
                                                               2003     (RESTATED)(1)
                                                              ------    -------------
                                                                   (IN MILLIONS)
<S>                                                           <C>       <C>
Cash flows from operating activities........................  $1,184        $ 526
Cash flows from investing activities........................    (671)          66
Cash flows from financing activities........................    (491)        (605)
</Table>

---------------

 (1) Cash flows from continuing operating, investing and financing activities
     were restated. However, the overall cash flows for 2002 were unaffected.

  Cash From Continuing Operating Activities

     Net cash provided by operating activities were $1.2 billion in 2003 versus
$0.5 billion in 2002. In our operating activities, we experienced a $0.8 billion
decline in 2003 in cash generated from our operations, before asset and
liability changes, primarily as a result of sales of operating assets during
both 2002 and 2003 and the effects of lower capital spending in our Production
segment. In 2003, changes in operating assets and liabilities were a source of
cash of $0.3 billion as compared to a use of cash of $1.1 billion in 2002.

  Cash From Continuing Investing Activities

     Net cash used in investing activities in 2003 consisted primarily of $994
million in capital expenditures. Offsetting this use of cash was $384 million of
proceeds from the sale of assets and investments. Our 2003 capital expenditures
includes the following (in millions):

<Table>
<Caption>

<S>                                                           <C>
Pipelines...................................................  $172
Production(1)...............................................   800
Field Services..............................................    17
Merchant Energy.............................................     5
                                                              ----
     Total..................................................  $994
                                                              ====
</Table>

---------------

 (1) Includes $72 million of capital expenditures paid in 2003 related to
     projects started and accrued in prior years, and $5 million spent on equity
     investments.

     Under our current plan, we expect to spend between approximately $306
million and $579 million in each of the next three years in our pipelines
segment for capital expenditures through a combination of internally generated
funds and external financing. These capital expenditures will be primarily spent
on maintenance and expansion projects.

     In our Production segment, we currently expect to reduce our total capital
expenditures from approximately $723 million in 2003 to approximately $340
million in 2004. In addition, we expect to receive additional funds from a
third-party investment program in 2004 that will allow us to expand our overall
capital development programs. Under this program, third parties contribute
capital for the drilling and development of a specific package of wells in
exchange for a net profits interest in each well. Based on disappointing results
in a portion of the program, one of the third party investors elected to cease
further investment in the program. See Item 8, Financial Statements and
Supplementary Data, Note 24, for a discussion of our third-party investment
program.

     We continually evaluate our capital expenditure program which is subject to
change based on market conditions. We will continue to pursue strategic
acquisitions of production properties and the development of projects subject to
acceptable returns.

                                        24
<PAGE>

     We will continue to divest our non-core assets based on the strategic
direction outlined in El Paso's Long-Range Plan (see Part I, Item 1, Business
for a further discussion of El Paso's Long-Range Plan and Item 8, Financial
Statements and Supplementary Data, Notes 3 and 10, for a further discussion of
these divestitures and other asset divestitures of our discontinued operations).

  Cash From Continuing Financing Activities

     Net cash used in financing activities in 2003 consisted primarily of
payments on affiliated notes payable of $1.4 billion, payments to retire
long-term debt of $0.6 billion and dividend payments to El Paso of $0.5 billion.
Offsetting this use of cash were $1.5 billion of capital contributions from our
parent and $0.4 billion of cash contributed by our discontinued operations.

  Cash Flows of Discontinued Operations

     During 2003, our discontinued operations generated $0.6 billion of cash
through sales of inventories at our refineries and asset sales, offset by
capital expenditures of $0.2 billion. These net cash inflows were distributed to
our continuing operations.

           CONTRACTUAL OBLIGATIONS AND OFF-BALANCE SHEET ARRANGEMENTS

     In the course of our business activities, we enter into a variety of
financing arrangements and contractual obligations. The following discusses
those contingent obligations, often referred to as off-balance sheet
arrangements. We also present aggregated information on our contractual cash
obligations, some of which are reflected in our financial statements, such as
short and long-term debt and other accrued liabilities. Other obligations such
as operating leases and capital commitments are not reflected in our financial
statements.

OFF-BALANCE SHEET ARRANGEMENTS AND RELATED LIABILITIES

  Guarantees

     We are involved in various joint ventures and other ownership arrangements
that sometimes require additional financial support that results in the issuance
of financial and performance guarantees. In a financial guarantee, we are
obligated to make payments if the guaranteed party fails to make payments under,
or violates the terms of, the financial arrangement. In a performance guarantee,
we provide assurance that the guaranteed party will execute on the terms of the
contract. If they do not, we are required to perform on their behalf. For
example, if the guaranteed party is required to deliver natural gas to a third
party and then fails to do so, we would be required to either deliver that
natural gas or make payments to the third party equal to the difference between
the contract price and the market value of the natural gas. As of December 31,
2003, we had approximately $43 million of both financial and performance
guarantees, including $23 million of guarantees related to our petroleum markets
discontinued operations, not otherwise reflected in our financial statements.
The remaining guarantees relate to our domestic and international power
operations.

                                        25
<PAGE>

CONTRACTUAL OBLIGATIONS

     The following table summarizes our contractual obligations as of December
31, 2003, for each of the years presented (all amounts are undiscounted and are
in millions):

<Table>
<Caption>
                                       2004   2005    2006    2007   2008   THEREAFTER    TOTAL
                                       ----   ----   ------   ----   ----   ----------   -------
<S>                                    <C>    <C>    <C>      <C>    <C>    <C>          <C>
Long-term financing obligations:(1)
  Principal..........................  $310   $363   $  654   $ 58   $476     $3,468     $ 5,329
  Interest...........................   398    373      350    313    300      3,195       4,929
Other contractual liabilities(2).....     7      8        5      4      2         19          45
Operating leases(3)..................    21     20       21     18     17         59         156
Other contractual commitments and
  purchase obligations:(4)
  Transportation and storage(5)......    43     42       40     37     37        132         331
  Other(6)...........................   185      6        1      1      0          0         193
                                       ----   ----   ------   ----   ----     ------     -------
  Total contractual obligations......  $964   $812   $1,071   $431   $832     $6,873     $10,983
                                       ====   ====   ======   ====   ====     ======     =======
</Table>

---------------

 (1) See Item 8, Financial Statements and Supplementary Data, Note 16.
 (2) Includes contractual, environmental and other obligations included in other
     noncurrent liabilities in our balance sheet.
 (3) See Item 8, Financial Statements and Supplementary Data, Note 18.
 (4) Other contractual commitments and purchase obligations are defined as
     legally enforceable agreements to purchase goods or services that have
     fixed or minimum quantities and fixed or minimum variable price provisions,
     and that detail approximate timing of the underlying obligations.
 (5) These are commitments for firm access to natural gas transportation and
     storage capacity.
 (6) Includes commitments for drilling and seismic activities in our production
     operations and various other maintenance, engineering, procurement and
     construction contracts used by our other operations.

                                        26
<PAGE>

                             RESULTS OF OPERATIONS

OVERVIEW

     In February 2004, we completed the December 31, 2003 reserve estimation
process for our proved natural gas and oil reserve estimates. The results of
this process indicated that a 1.0 Tcfe downward revision in our proved reserves
was needed. After an investigation into the factors that caused this revision,
it was determined that a material portion of these reserve revisions should be
reflected in the historical periods in this Annual Report on Form 10-K.
Accordingly, our historical financial results for 1999 through 2002 and for the
first three quarters of 2003 were restated. See Item 8, Financial Statements and
Supplementary Data, Note 1, for a further discussion of the restatement.

     Our management, as well as El Paso's management, uses earnings before
interest and income taxes (EBIT) to assess the operating results and
effectiveness of our business segments. We define EBIT as net income (loss)
adjusted for (i) items that do not impact our income (loss) from continuing
operations, such as extraordinary items, discontinued operations and the impact
of accounting changes, (ii) income taxes, (iii) interest and debt expense and
(iv) distributions on preferred interests of consolidated subsidiaries. Our
business consists of consolidated operations as well as investments in
unconsolidated affiliates. We exclude interest and debt expense and
distributions on preferred interests of consolidated subsidiaries so that
investors may evaluate our operating results without regard to our financing
methods or capital structure. We believe EBIT is helpful to our investors
because it allows them to more effectively evaluate the operating performance of
both our consolidated businesses and our unconsolidated investments using the
same performance measure analyzed internally by our management. EBIT may not be
comparable to measurements used by other companies. Additionally, EBIT should be
considered in conjunction with net income and other performance measures such as
operating income or operating cash flow.

     Below is a reconciliation of our consolidated operating income (loss) to
our EBIT and our EBIT to our consolidated net loss for each of the three years
ended December 31:

<Table>
<Caption>
                                                                         2002         2001
                                                             2003     (RESTATED)   (RESTATED)
                                                            -------   ----------   ----------
                                                                      (IN MILLIONS)
<S>                                                         <C>       <C>          <C>
Operating revenues........................................  $ 2,374    $ 3,826      $ 3,964
Operating expenses........................................   (1,854)    (3,049)      (4,310)
                                                            -------    -------      -------
  Operating income (loss).................................      520        777         (346)
Earnings (loss) from unconsolidated affiliates............      (12)       113          220
Other.....................................................       71         --           63
                                                            -------    -------      -------
  EBIT....................................................      579        890          (63)
Interest and debt expense.................................     (403)      (421)        (420)
Affiliated interest expense, net..........................      (41)        (9)         (46)
Distributions on preferred interests of consolidated
  subsidiaries............................................      (17)       (35)         (51)
Income taxes..............................................       57       (109)          87
                                                            -------    -------      -------
  Income (loss) from continuing operations................      175        316         (493)
Discontinued operations, net of income taxes..............   (1,297)      (365)         (85)
Extraordinary items, net of income taxes..................       --         --          (11)
Cumulative effect of accounting changes, net of income
  taxes...................................................      (12)        14           --
                                                            -------    -------      -------
  Net loss................................................  $(1,134)   $   (35)     $  (589)
                                                            =======    =======      =======
</Table>

SEGMENT RESULTS

     Our current business segments are Pipelines, Production, Field Services and
Merchant Energy. These segments provide a variety of energy products and
services. They are managed separately as each business unit

                                        27
<PAGE>

requires different technology, operational and marketing strategies. We
reclassified our historical coal mining operations in the second quarter of 2002
and our petroleum markets operations in the second quarter of 2003 from our
Merchant Energy segment to discontinued operations in our financial statements.
Our Merchant Energy segment's results for all periods presented reflect this
change. In December 2003, El Paso announced its Long-Range Plan. Under the
Long-Range Plan, our business will be divided into two primary business lines:
regulated and unregulated. Our regulated businesses will include our existing
Pipelines segment, while our unregulated businesses will include our Production,
Field Services and Merchant Energy segments. Below is a summary of EBIT by
segment, followed by a discussion of the year over year results of each of our
business segments, our corporate activities, interest and debt expense,
affiliated interest expense, distributions on preferred interests of
consolidated subsidiaries, income taxes and the results of our discontinued
petroleum markets and coal mining operations.

<Table>
<Caption>
                                                                     2002         2001
EBIT BY SEGMENT                                            2003   (RESTATED)   (RESTATED)
---------------                                            ----   ----------   ----------
                                                                   (IN MILLIONS)
<S>                                                        <C>    <C>          <C>
Regulated Businesses
  Pipelines..............................................  $500      $537        $ 292
Unregulated Businesses
  Production.............................................    92       (52)         163
  Field Services.........................................   (52)       15           72
  Merchant Energy........................................    24       409          108
                                                           ----      ----        -----
  Segment EBIT...........................................   564       909          635
Corporate and other......................................    15       (19)        (698)
                                                           ----      ----        -----
  Consolidated EBIT from continuing operations...........  $579      $890        $ (63)
                                                           ====      ====        =====
</Table>

     As indicated above, the results for 2002 and 2001, as well as for the nine
months ended September 30, 2003 have been restated for adjustments to our
natural gas reserve estimates. See Item 8, Financial Statements and
Supplementary Data, Note 1 for a further discussion of the restatement and the
manner in which our segments were affected.

PIPELINES SEGMENT

     Our Pipelines segment consists of interstate natural gas transmission,
storage and related services in the U.S. Our interstate natural gas
transportation systems face varying degrees of competition from other pipelines,
as well as from alternative energy sources used to generate electricity, such as
hydroelectric power, nuclear, coal and fuel oil. In addition, some of our
customers have shifted from a traditional dependence solely on long-term
contracts to a portfolio approach which balances short-term opportunities with
long-term commitments. This shift has impacted the volatility of our revenues,
and is due to changes in market conditions and competition driven by state
utility deregulation, local distribution company mergers, new supply sources,
volatility in natural gas prices, demand for short-term capacity and new markets
in power plants.

     We are regulated by the FERC, which regulates the rates we can charge our
customers. These rates are a function of our costs of providing services to our
customers, including a reasonable return on our invested capital. As a result,
our revenues have historically been relatively stable. However, they can be
subject to volatility due to factors such as weather, changes in natural gas
prices and market conditions, regulatory actions, competition and the
credit-worthiness of our customers. In addition, our ability to extend our
existing customer contracts or re-market expiring contracted capacity is
dependent on competitive alternatives, the regulatory environment at the
federal, state and local levels and market supply and demand factors at the
relevant dates these contracts are extended or expire. The duration of new or
renegotiated contracts will be affected by current prices, competitive
conditions and judgments concerning future market trends and volatility. Subject
to regulatory constraints, we attempt to re-contract or re-market our capacity
at the maximum rates allowed under our tariffs, although, at times, we discount
these rates to remain competitive. The level of discount varies for each of our
pipeline systems.

                                        28
<PAGE>

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

PIPELINES SEGMENT RESULTS

<Table>
<Caption>
                                                           2003          2002          2001
                                                         ---------     ---------     ---------
                                                         (IN MILLIONS, EXCEPT VOLUME AMOUNTS)
<S>                                                      <C>           <C>           <C>
Operating revenues(1)..................................   $  918        $  934        $1,054
Operating expenses(1)..................................     (521)         (515)         (859)
                                                          ------        ------        ------
  Operating income.....................................      397           419           195
Other income...........................................      103           118            97
                                                          ------        ------        ------
  EBIT.................................................   $  500        $  537        $  292
                                                          ======        ======        ======
Throughput volumes (BBtu/d)(2).........................    8,158         8,087         8,109
                                                          ======        ======        ======
</Table>

---------------
(1) Within our revenues and operating expenses are amounts related to our Dakota
    gasification facility. This contract had minimal impact on operating income
    or EBIT. For the years ended December 31, 2003, 2002 and 2001, revenues on
    this contract were $32 million, $31 million and $50 million, and operating
    expenses were $31 million, $27 million and $49 million.
(2) Throughput excludes volumes related to our equity investment in the Alliance
    Pipeline system which was sold. Throughput volumes exclude intrasegment
    activities. Prior period volumes have been revised to be consistent with the
    current year presentation which includes billable transportation throughput
    volume for storage withdrawal.

  Year Ended December 31, 2003 Compared to Year Ended December 31, 2002

     For the year ended December 31, 2003, our EBIT was $37 million lower than
in 2002. Lower operating revenues and non-operating income contributed to the
reduced EBIT levels.

     Our lower 2003 EBIT was impacted by a number of revenue items. In July
2002, CIG sold its Panhandle field and other production properties which reduced
2003 revenues by $50 million and resulted in an EBIT decline of $29 million.
Transportation and storage revenues decreased $10 million due to contract
changes relating to ANR's significant customer, We Energies. These direct
impacts to EBIT were offset by the completion of the Front Range and other
system expansions during 2002 and 2003, and new transportation contracts which
resulted in higher reservation revenues of $17 million and EBIT of $15 million.
We also experienced higher revenues and EBIT of $11 million due to higher
volumes and prices on natural gas retained by our regulated systems in excess of
amounts we used in our pipeline operations.

     Our lower 2003 EBIT was also impacted by lower other non-operating income
of $15 million. The decrease was primarily due to lower 2003 equity earnings of
$20 million from our investment in Alliance Pipeline, which was sold in the
first quarter of 2003, and $11 million from the favorable resolution of
uncertainties in 2002 associated with the sale of our interests in the Iroquois
and Empire State pipeline systems and Gulfstream pipeline project.

     Finally, our 2003 EBIT was favorably impacted by our re-application of
Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the
Effects of Certain Types of Regulation, by our CIG and WIC systems, resulting in
an $18 million one-time increase in other income. This income resulted from our
recording the regulatory assets of these systems. SFAS No. 71 allows a company
to capitalize items that will be considered in future rate making actions and
this income resulted from the capitalization of those items that we believe will
be considered in CIG's and WIC's future rate cases. At the same time CIG and WIC
re-applied SFAS No. 71, they adopted the FERC depreciation rate for their
regulated plant and equipment. This change will result in depreciation expense
increases in the future of approximately $9 million annually. Based on our
estimates, we anticipate that the overall annual EBIT impact as a result of our
re-application of SFAS No. 71 will be an annual reduction of EBIT of
approximately $10 million.

  Year Ended December 31, 2002 Compared to Year Ended December 31, 2001.

     Our EBIT for 2002 increased $245 million from 2001. The increase primarily
resulted from $192 million of merger-related charges incurred in 2001 following
our merger with El Paso and $27 million of lower

                                        29
<PAGE>

general, administrative and operating costs in 2002 as a result of cost
efficiencies following this merger. Also contributing to the EBIT increase were
a favorable impact from system expansions, which were placed in service in late
2001 resulting in increased revenue in 2002 of $30 million, operating expenses
of $8 million and EBIT of $22 million, $18 million from lower amortization of
goodwill due to the implementation of SFAS No. 142 in 2002, and an $11 million
gain on the sale of pipeline expansion rights in February 2002. Partially
offsetting these EBIT increases was a reduction of $27 million as a result of
CIG's sale of its Panhandle field in July 2002, a $28 million decrease in
revenues and EBIT due to lower sales of our natural gas retained on our
regulated systems in excess of amounts used in our operations, and $22 million
of lower transportation revenues due to milder weather in 2002.

PRODUCTION SEGMENT

     Our Production segment results have been restated for revisions to our
natural gas and oil reserve estimates. Our Production segment conducts our
natural gas and oil exploration and production activities. Our operating results
are driven by a variety of factors including the ability to locate and develop
economic natural gas and oil reserves, extract those reserves with minimal
production costs and sell the products at attractive prices. Consistent with El
Paso's Long-Range Plan announced in December 2003, El Paso's long-term strategy
includes developing production opportunities primarily in the U.S. and Brazil,
while prudently divesting of production properties outside of these regions. As
of September 2004, we have sold our production operations in Canada and
substantially all of our operations in Indonesia. Our operations in Canada
include activities in Nova Scotia where, in the first quarter of 2004, we
drilled an exploratory well that was not commercially viable and recorded a $24
million ceiling test charge.

     In June 2004, El Paso announced a back-to-basics plan for its production
business. This plan emphasizes strict capital discipline designed to improve
capital efficiency through the use of standardized risk analysis, a heightened
focus on cost control, and revised controls for booking proved natural gas and
oil reserves. This back-to-basics approach is expected to stabilize production
by improving the production mix across its operating areas, thereby generating
more predictable income and cash flows in the production business.

  Reserves and Costs

     In February 2004, we completed estimates of our proved natural gas and oil
reserves as of December 31, 2003. These estimates were prepared internally by
us. Ryder Scott Company and Huddleston & Co., Inc., independent petroleum
engineering firms, performed independent reserve estimates of our proved
reserves for 84 percent and 16 percent of our properties. The total estimate of
proved reserves prepared by these engineers is within five percent of our
internally prepared estimates.

     The proved reserve estimates as of December 31, 2003, indicated a 1.0 Tcfe
downward revision of our proved natural gas and oil reserves was needed. The
downward revisions related primarily to our Texas onshore and offshore Gulf of
Mexico regions. Due to the significance of the reserve revision, the Audit
Committee of El Paso's Board of Directors engaged a law firm to conduct an
independent investigation into the reasons for the revisions. The investigation
concluded that a material portion of these revisions related to prior periods,
and as a result we restated our historical reserve estimates and our historical
financial information derived from these estimates. The reserve restatement
involved utilizing the reserve estimate prepared as of December 31, 2003 and
then reconstructing historical reserve data using actual historical production
data and re-engineered sales of proved reserves. Following this reserve
reconstruction and the recalculation of the discounted future net cash flows,
ceiling test calculations, depletion rates, and gains and losses on asset sales
were recomputed for each period restated. See Item 8, Financial Statements and
Supplementary Data, Notes 1, 7 and 24 for a discussion of our ceiling test
calculation and the restatement of our natural gas and oil reserves. The
restatement will result in a lower depletion rate and reduced exposure to
ceiling test charges in the future than would have been the case absent the
restatement.

     Since December 31, 2001, we have sold approximately 781 Bcfe of proved
reserves in multiple sales transactions with various third parties. The sale of
these reserves, combined with normal production declines, mechanical failures on
certain producing wells and disappointing drilling results, have resulted in our
total

                                        30
<PAGE>

equivalent production levels declining each quarter since the first quarter of
2002. For 2003, our total equivalent production has declined approximately 117
Bcfe or 38 percent as compared to 2002. In addition, since our depletion rate is
determined under the full cost method of accounting, we expect a higher
depletion rate as a result of higher finding and development costs experienced
this year, coupled with a significantly lower reserve base. After taking into
consideration the restatement of our natural gas and oil reserves for prior
periods, our unit of production depletion rate was approximately $2.26 per Mcfe
and $2.32 per Mcfe for the first and second quarters of 2004. We expect this
rate to be approximately $2.48 per Mcfe for the third quarter of 2004. See Item
8, Financial Statements and Supplementary Data, Note 24, for a discussion of our
natural gas and oil reserves. For the first eight months of 2004, daily
production has averaged 367 MMcfe/d; however, for the month of August 2004,
production averaged approximately 325 MMcfe/d. Our future trends in production
and our depreciation, depletion and amortization rates will be dependent upon
the amount of capital allocated to our Production segment, the level of success
in our drilling programs and future sales activities relating to our proved
reserves.

 Production Hedging

     We have historically engaged in hedging activities, primarily through
natural gas and oil swaps, on our natural gas and oil production to stabilize
cash flows and reduce the risk of downward commodity price movements on our
sales. Because this hedging strategy only partially limits our exposure to
changes in commodity prices, we can experience significant volatility in our
reported results of operations, financial position and cash flows from period to
period. During 2003 and so far in 2004, we did not add additional hedges on our
future production. As of December 31, 2003, we have hedged 12,750 BBtu of
natural gas in each quarter of 2005 at an average price of $3.31.

  Operating Results

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

<Table>
<Caption>
                                                                       2002            2001
              PRODUCTION SEGMENT RESULTS                  2003     (RESTATED)(1)   (RESTATED)(1)
              --------------------------                --------   -------------   -------------
                                                        (IN MILLIONS, EXCEPT VOLUMES AND PRICES)
<S>                                                     <C>        <C>             <C>
Operating revenues:
  Natural gas.........................................  $    741     $  1,091        $  1,562
  Oil, condensate and liquids.........................       160          162             200
  Other...............................................         9            5              21
                                                        --------     --------        --------
         Total operating revenues.....................       910        1,258           1,783
Transportation and net product costs..................       (44)         (52)            (56)
                                                        --------     --------        --------
         Total operating margin.......................       866        1,206           1,727
                                                        --------     --------        --------
Depreciation, depletion and amortization..............      (377)        (468)           (658)
Production costs(2)...................................      (124)        (182)           (234)
Ceiling test and other charges(3).....................      (202)        (526)           (609)
General and administrative expenses...................       (82)         (84)            (63)
Taxes, other than production and income taxes.........        (1)          (3)             (5)
                                                        --------     --------        --------
         Total operating expenses(4)..................      (786)      (1,263)         (1,569)
                                                        --------     --------        --------
  Operating income (loss).............................        80          (57)            158
Other income..........................................        12            5               5
                                                        --------     --------        --------
  EBIT................................................  $     92     $    (52)       $    163
                                                        ========     ========        ========
Volumes, prices and cost per unit:
  Natural gas
    Volumes (MMcf)....................................   156,685      263,749         385,793
                                                        ========     ========        ========
    Average realized prices including hedges
       ($/Mcf)(5).....................................  $   4.73     $   4.14        $   4.05
                                                        ========     ========        ========
    Average realized prices excluding hedges
       ($/Mcf)(5).....................................  $   5.38     $   3.09        $   4.18
                                                        ========     ========        ========
    Average transportation costs ($/Mcf)..............  $   0.22     $   0.16        $   0.07
                                                        ========     ========        ========
</Table>

                                        31
<PAGE>

<Table>
<Caption>
                                                                       2002            2001
              PRODUCTION SEGMENT RESULTS                  2003     (RESTATED)(1)   (RESTATED)(1)
              --------------------------                --------   -------------   -------------
                                                        (IN MILLIONS, EXCEPT VOLUMES AND PRICES)
<S>                                                     <C>        <C>             <C>
  Oil, condensate and liquids
    Volumes (MBbls)...................................     6,287        7,981           8,787
                                                        ========     ========        ========
    Average realized prices including hedges
       ($/Bbl)(5).....................................  $  25.40     $  20.31        $  22.81
                                                        ========     ========        ========
    Average realized prices excluding hedges
       ($/Bbl)(5).....................................  $  25.40     $  20.28        $  22.75
                                                        ========     ========        ========
    Average transportation costs ($/Bbl)..............  $   0.89     $   0.62        $   0.65
                                                        ========     ========        ========
  Production cost ($/Mcfe)
    Average lease operating cost......................  $   0.47     $   0.52        $   0.38
    Average production taxes..........................      0.16         0.07            0.15
                                                        --------     --------        --------
         Total production cost(2).....................  $   0.63     $   0.59        $   0.53
                                                        ========     ========        ========
Average general and administrative expenses
  ($/Mcfe)............................................  $   0.42     $   0.27        $   0.14
                                                        ========     ========        ========
Unit of production depletion cost ($/Mcfe)............  $   1.82     $   1.47        $   1.48
                                                        ========     ========        ========
</Table>

---------------
(1) Amounts restated include depreciation, depletion, and amortization, and
    ceiling test and other charges as well as related subtotals and totals.
    Additionally, unit of production depletion cost has been restated.
(2) Production costs includes lease operating costs and production related taxes
    (including ad valorem and severance taxes).
(3) Includes ceiling test charges, restructuring and merger-related costs, asset
    impairments, gain (loss) on long-lived assets and changes in accounting
    estimates.
(4) Transportation costs are included in operating expenses on our consolidated
    statements of income.
(5) Prices are stated before transportation costs.

  Year Ended December 31, 2003 Compared to Year Ended December 31, 2002

     For the year ended December 31, 2003, EBIT was $144 million higher than in
2002. The increase was primarily due to lower ceiling test and other charges,
lower depreciation, depletion and amortization expense and lower production
costs, partially offset by lower natural gas, oil, condensate and liquids
volumes as a result of asset sales, normal production declines and disappointing
drilling results.

     Operating Revenues.  The following table describes the variance in revenue
between 2003 and 2002 due to (i) changes in average realized market prices
excluding hedges, (ii) changes in production volumes, and (iii) the effects of
hedges on our revenues.

<Table>
<Caption>
                                                                 VARIANCE
                                                    -----------------------------------
PRODUCTION REVENUE VARIANCE ANALYSIS                PRICES    VOLUMES    HEDGE    TOTAL
------------------------------------                ------    -------    -----    -----
                                                               (IN MILLIONS)
<S>                                                 <C>       <C>        <C>      <C>
Natural gas.......................................   $358      $(331)    $(377)   $(350)
Oil, condensate and liquids.......................     32        (34)       --       (2)
Other.............................................                                    4
                                                     ----      -----     -----    -----
  Operating revenue variance......................   $390      $(365)    $(377)   $(348)
                                                     ====      =====     =====    =====
</Table>

     Our 2003 operating revenues decreased $348 million as compared to 2002
primarily due to lower production volumes. Production volume declines were
primarily due to the sale of properties in New Mexico, Texas, Colorado, Utah,
offshore Gulf of Mexico, and western Canada, as well as normal production
declines and mechanical failures in certain producing wells.

     Average realized natural gas prices in 2003, excluding hedges, were $2.29
per Mcf higher than in 2002, an increase of 74 percent. However, more than
offsetting the increase in revenues due to higher natural gas prices were $101
million of hedging losses in 2003 as compared to $276 million in hedging gains
in 2002 relating to our natural gas hedge positions. These hedging losses and
gains represent the difference between our hedge price and the market price at
the time the hedge positions were settled. We will recognize a hedging loss in
2004 related to natural gas hedge positions that were de-designated during 2002
at higher prices than the

                                        32
<PAGE>

original hedged price. This resulted in a loss that is currently deferred in
accumulated other comprehensive income and will be recognized through earnings
in 2004 upon physical delivery of the hedged commodity.

     Operating Expenses.  Total operating expenses were $477 million lower in
2003 as compared with 2002 primarily due to lower ceiling test and other
charges, lower depreciation, depletion, and amortization expense and lower
production costs.

     Ceiling test and other charges were $324 million lower in 2003 compared
with 2002. In 2003, we incurred ceiling test charges of $109 million, which
included $61 million for our Canadian full cost pool, $34 million for our
domestic full cost pool, and $14 million for our other international operations.
In addition, in 2003 we recorded a $75 million impairment of the goodwill
associated with our Canadian operations. In 2002, we incurred $521 million in
ceiling test charges, of which $417 million related to our domestic full cost
pool, $91 million to our Canadian full cost pool and $13 million related to our
other international assets.

     Total depreciation, depletion, and amortization expense decreased by $91
million in 2003 as compared to 2002 primarily due to lower production volumes in
2003 due to the asset sales, normal production declines, and mechanical failures
in certain producing wells mentioned above. These lower production volumes
reduced our depreciation, depletion and amortization expenses by $172 million.
This decrease was partially offset by an increase of $69 million from higher
depletion rates as a result of higher finding and development costs in 2003 and
a lower reserve base due to asset sales. We also incurred $16 million in 2003
for the accretion of our liability for asset retirement obligations.

     Production costs decreased by $58 million in 2003 as compared to 2002 as a
result of the asset sales noted above. However, our production cost per unit in
2003 increased by 7 percent or $0.04/Mcfe primarily as a result of higher
production taxes in 2003 due to higher natural gas and oil prices and higher tax
credits taken in 2002 on high cost natural gas wells.

  Year Ended December 31, 2002 Compared to Year Ended December 31, 2001

     For the year ended December 31, 2002, EBIT was $215 million lower than in
2001. The decrease was primarily due to lower natural gas volumes due to asset
sales and normal production declines. Partially offsetting the decrease was
lower ceiling test and other charges, lower depreciation, depletion and
amortization expense, and lower production costs primarily due to the lower
production volumes mentioned above.

     Operating Revenues.  The following table describes the variance in revenue
between 2002 and 2001 due to: (i) changes in average realized market prices
excluding hedges, (ii) changes in production volumes, and (iii) the effects of
hedges on our revenues.

<Table>
<Caption>
                                                                VARIANCE
                                                   -----------------------------------
PRODUCTION REVENUE VARIANCE ANALYSIS               PRICES    VOLUMES    HEDGE    TOTAL
------------------------------------               ------    -------    -----    -----
                                                              (IN MILLIONS)
<S>                                                <C>       <C>        <C>      <C>
Natural gas......................................  $(287)     $(510)    $326     $(471)
Oil, condensate and liquids......................    (20)       (18)      --       (38)
Other............................................                                  (16)
                                                   -----      -----     ----     -----
  Operating revenue variance.....................  $(307)     $(528)    $326     $(525)
                                                   =====      =====     ====     =====
</Table>

     Our 2002 operating revenues decreased $525 million as compared to 2001
primarily due to lower production volumes. The volume decline in natural gas and
oil, condensate, and liquids were primarily due to the sale of properties in
Colorado, Utah and Texas as well as normal production declines.

     Average realized natural gas prices, excluding hedges, were $1.09 per Mcf
lower than in 2001, a decrease of 26 percent. However, more than offsetting this
reduction were $276 million of hedging gains in 2002 as compared to $50 million
of hedging losses in 2001 relating to our natural gas hedge positions. These
hedging losses and gains represent the difference between our hedge price and
the market price at the time the hedge positions were settled.

                                        33
<PAGE>

     Operating Expenses.  Total operating expenses were $306 million lower in
2002 as compared to 2001 due primarily to lower depreciation, depletion and
amortization, lower ceiling test and other charges, and lower production costs,
partially offset by higher general and administrative expenses.

     Total depreciation, depletion and amortization decreased in 2002 by $190
million as compared to 2001 primarily due to lower production volumes in 2002
due to the asset sales and normal production declines mentioned above. These
lower production volumes reduced our depreciation, depletion and amortization
expenses by $188 million.

     Ceiling test and other charges decreased by $83 million in 2002 as compared
with 2001. Our 2002 non-cash full cost ceiling test charges of $521 million
included $417 million for our domestic full cost pool, $91 million for our
Canadian full cost pool, and $13 million for our other international operations.
In 2001, we incurred ceiling test charges of $537 million, of which $257 million
related to our domestic full cost pool, $225 million related to our Canadian
full cost pool, $50 million related to our Brazilian full cost pool, and $5
million to our other international operations. We also incurred $45 million of
merger related costs, $16 million of asset impairments and $10 million of
write-downs of materials and supplies following the merger with El Paso in 2001.

     Production costs were $52 million lower in 2002 as a result of the asset
sales noted above and to lower production taxes in 2002 due to lower natural gas
and oil prices and tax credits taken in 2002 on high cost natural gas wells.
However, our production costs per unit increased 11 percent or $0.06 per Mcfe
due to lower production volumes and an increase in the mix of oil production
versus gas production which has a higher operating cost per unit.

     General and administrative expenses were $21 million or $0.13 per Mcfe
higher than in 2001, an increase of 93 percent on a per unit basis primarily due
to higher corporate overhead allocations, offset by higher capitalized costs.

FIELD SERVICES SEGMENT

     Our Field Services segment conducts our midstream activities which includes
processing and gathering of natural gas. For the majority of 2003, our assets
principally consisted of our consolidated processing assets in south Louisiana.

  Processing and Gathering Operations

     We attempt to balance earnings in our processing and gathering business
through a combination of fixed fee-based and market-based services. A majority
of our gathering operations earn margins from fixed-fee-based services. However,
some of these operations earn margins from market-based rates. Revenues from
these market-based rate services are the product of the market price, usually
related to the monthly natural gas price index and the volume gathered. Our
processing operations earn a margin based on fixed-fee contracts,
percentage-of-proceeds contracts and make-whole contracts.
Percentage-of-proceeds contracts allow us to retain a percentage of the product
as a fee for the service provided. Make-whole contracts allow us to retain the
extracted liquid products and return to the producer a Btu equivalent amount of
natural gas. Under our percentage-of-proceeds contracts and make-whole
contracts, we may have more sensitivity to price changes during periods when
natural gas and NGL prices are volatile.

  Asset Sales

     During 2003, we sold our gathering systems located in Wyoming to Western
Gas Resources, Inc. We also sold our midstream assets in the Mid-Continent
region to Regency Gas Services, LLC, an investment of Charlesbank Capital
Resources, LLC. Our Mid-Continent assets primarily included our Greenwood,
Hugoton, Keyes and Mocane natural gas gathering systems, our Sturgis, Mocane and
Lakin processing plants and our processing arrangements at three additional
processing plants.

                                        34
<PAGE>

     Following the sales activities discussed above, our remaining assets now
consist primarily of our processing and gathering facilities in south Louisiana.
Furthermore, these actions have resulted in significant EBIT reductions.

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

<Table>
<Caption>
              FIELD SERVICES SEGMENT RESULTS                   2003       2002       2001
              ------------------------------                 --------   --------   --------
                                                              (IN MILLIONS, EXCEPT VOLUMES
                                                                      AND PRICES)
<S>                                                          <C>        <C>        <C>
Processing and gathering gross margins(1)..................   $   59     $  112     $  155
Operating expenses.........................................      (18)       (44)       (99)
                                                              ------     ------     ------
  Operating income.........................................       41         68         56
Other income (expenses)....................................      (93)       (53)        16
                                                              ------     ------     ------
  EBIT.....................................................   $  (52)    $   15     $   72
                                                              ======     ======     ======
Volumes and Prices:
  Gathering
     Volumes (BBtu/d)......................................      101        628        843
                                                              ======     ======     ======
     Prices ($/MMBtu)......................................   $ 0.14     $ 0.13     $ 0.14
                                                              ======     ======     ======
  Processing
     Volumes (inlet BBtu/d)................................    1,687      1,754      1,966
                                                              ======     ======     ======
     Prices ($/MMBtu)......................................   $ 0.11     $ 0.12     $ 0.14
                                                              ======     ======     ======
</Table>

---------------

(1) Gross margins consist of operating revenues less cost of products sold. We
    believe this measurement is more meaningful for understanding and analyzing
    our Field Services operating results because commodity costs play such a
    significant role in the determination of profit from our midstream
    activities.

  Year Ended December 31, 2003 Compared to Year Ended December 31, 2002

     For the year ended December 31, 2003, our EBIT was $67 million lower than
2002. Our asset sales in 2003 and 2002 contributed a year over year decrease in
our EBIT of $18 million. We also had a net increase of $38 million year over
year relating to impairment charges, write-down of goodwill, and net loss on
sale of assets and investments.

     The decrease in our processing and gathering gross margins for the year
ended December 31, 2003, was primarily due to lower margins of $35 million as a
result of asset sales which included the Dragon Trail gas processing plant in
May 2002, Natural Buttes and Ouray natural gas gathering systems in December
2002, Wyoming gathering assets in January 2003, Mid-Continent gathering and
processing assets in June 2003, and $7 million related to the transfer of our
Gilmore assets to a subsidiary of El Paso.

     Operating expenses for year ended December 31, 2003, were $26 million lower
than in 2002. During 2003, we realized $19 million in net gains from the sales
of assets noted above versus $35 million in 2002. These sales contributed to
lower operating costs and depreciation expense in 2003 totaling $24 million. In
addition, we recorded a $14 million loss associated with our write-down of
goodwill in 2002.

     Other non-operating expenses increased $40 million due to $86 million in
impairment charges in 2003 related to our Dauphin Island Gathering Partners and
Mobile Bay Processing Partners investments. The impairment was recorded based on
the pending sales of our interests in these investments which closed in August
2004. Partially offsetting this increase were losses on the sale of our
investment in the Aux Sable NGL plant and our Blacks Fork natural gas processing
plant in 2002 totaling $50 million.

  Year Ended December 31, 2002 Compared to Year Ended December 31, 2001

     For the year ended December 31, 2002, our EBIT was $57 million lower than
in 2001. This decrease was the result of lower processing and gathering margins
of $43 million of which $37 million was due to lower

                                        35
<PAGE>

NGL prices in 2002 and natural declines in production in 2002, which unfavorably
impacted our volumes and margins in the Rocky Mountain and south Louisiana
regions. We also experienced lower margins of $6 million related to the sale of
our Dragon Trail processing plant in May 2002.

     Operating expenses for the year ended December 31, 2002, were $55 million
lower than in 2001. The decrease was due to $35 million of gains in 2002 on the
sales of our Natural Buttes and Ouray natural gas gathering systems and our
Dragon Trail processing plant, merger-related costs of $13 million in connection
with our 2001 merger with El Paso and a change in our 2001 estimated
environmental remediation liabilities of $9 million. Also contributing to the
decrease was $14 million of lower expenses as a result of the sale of our Dragon
Trail processing plant and our cost reduction plan in 2002. The decrease was
partially offset by a $14 million goodwill impairment that resulted from the
sale of assets during 2002.

     Other non-operating income for the year ended December 31, 2002, was $69
million lower than in 2001. The decrease was due to the losses on the sale in
2002 of our investment in the Aux Sable NGL plant and our investment in the
Blacks Fork natural gas processing plant of $47 million and $3 million. Also
contributing to the decrease in other income for 2002 was a $13 million gain on
the sale of our investment in Deepwater Holdings in October 2001 and $6 million
of lower equity earnings from Deepwater Holdings as a result of the sale of our
interests to GulfTerra in October 2001.

MERCHANT ENERGY SEGMENT

     Our Merchant Energy segment consists of the ownership and operation of
domestic and international power plants, including consolidated plants and
equity investments. As part of El Paso's Long-Range Plan, El Paso announced its
intent to dispose of a majority of our domestic and international power
operations over the next several years. In December 2003, El Paso's Board
approved the sale of substantially all of our domestic power plant operations,
which we expect to complete in 2004. The future results of our Merchant Energy
segment will be impacted by the timing of these sales. Historically, it also had
a petroleum markets division. In 2003, El Paso's Board of Directors approved the
sale of these petroleum markets operations and, as a result, we reclassified
that division as discontinued operations for all periods presented.

     Our operations include contracted and merchant power operations and the
results of our power restructuring business. Our contracted power operations
include power plants that have dedicated power contracts with customers
(generally electric utilities and governmental agencies) for the generation and
sale of power. Since the long-term sales contracts and long-term fuel contracts
in these operations generally contain fixed prices, operating results in this
business are fairly stable.

     Our merchant power operations include plants that operate during peak
periods without dedicated power contracts. Generally, these plants operate when
there is demand for their power and when the market price of power exceeds the
plant's variable costs of generating power. Many of our merchant plants have
contractual obligations, such as transportation capacity contracts, that
represent fixed costs for the plant. Our ability to recover these fixed
operating costs depends largely on electricity demand and the volume of power
generated as well as the margins that can be realized.

     In 2001 and 2002, we restructured several above-market, long-term power
sales contracts with regulated utilities that were originally tied to older
power plants built under PURPA. These contracts were amended so that the power
sold to the utilities was not required to be delivered from the specified power
generation plant, but could be obtained in the wholesale power market. For a
further discussion of our power restructuring activities, see Item 8, Financial
Statements and Supplementary Data, Note 12. Since December 31, 2003, we have
sold two of our domestic power plants and all of our power restructuring
activities for proceeds of approximately $92 million and the assumption by the
buyer of approximately $887 million in debt. As a result of our credit
downgrades and economic changes in the power market, we are no longer pursuing
additional power contract restructuring activities.

                                        36
<PAGE>

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

<Table>
<Caption>
MERCHANT ENERGY SEGMENT RESULTS                               2003    2002    2001
-------------------------------                               -----   -----   ----
                                                                 (IN MILLIONS)
<S>                                                           <C>     <C>     <C>
Gross margin(1).............................................  $ 160   $ 665   $ 42
Operating expenses..........................................   (153)   (280)   (83)
                                                              -----   -----   ----
     Operating income (loss)................................      7     385    (41)
Other income................................................     17      24    149
                                                              -----   -----   ----
  EBIT......................................................  $  24   $ 409   $108
                                                              =====   =====   ====
</Table>

---------------

(1) Gross margin consists of revenues from our power plants and the initial net
    gains and losses incurred in connection with the restructuring of power
    contracts, as well as the subsequent revenues, cost of electricity purchases
    and changes in fair value of those contracts. The cost of fuel used in the
    power generation process is included in operating expenses.

  Year Ended December 31, 2003 Compared to Year Ended December 31, 2002

     For the year ended December 31, 2003, our EBIT was $385 million lower than
in 2002. This decrease is due primarily to the fact that we restructured the
power sales contracts at our Eagle Point (also known as UCF) and Nejapa power
plants in 2002, which resulted in a $436 million gain, net of minority interest
and other transaction costs. Also contributing to this decrease was a $41
million decrease in the operating income at our Eagle Point power plant in 2003,
following the restructuring of its power contract in March 2002. We also
recorded a $43 million impairment of our equity investment in the Bastrop power
plant in 2003 based on our anticipated sale of the plant, which was completed in
the second quarter of 2004. Partially reducing this 2003 decrease in EBIT was a
$64 million increase in the fair value of our UCF restructured power contract in
2003, and a $90 million contract termination fee we paid in 2002 to terminate a
steam contract between our Eagle Point power plant and the Eagle Point refinery
(which is included in discontinued operations) which has been eliminated in
consolidation.

  Year Ended December 31, 2002 Compared to Year Ended December 31, 2001

     For the year ended December 31, 2002, our EBIT was $301 million higher than
in 2001. This increase is primarily due to the fact that we restructured the
power sales contracts at our Eagle Point (also known as UCF) and Nejapa power
plants in 2002, which resulted in a $436 million gain, net of minority interest
and other transaction costs. This gain was partially offset by an $18 million
write-down of power turbines. In 2002, El Paso reduced its capital expenditure
plans related to future development of power projects because of its liquidity
concerns, and as a result its ability and intent to use the turbines in its
international and domestic power development projects had changed. Also
offsetting the increase was a $90 million contract termination fee we paid in
2002 to terminate a steam contract between our Eagle Point power plant and the
Eagle Point refinery (which is included in discontinued operations) which has
been eliminated in consolidation.

CORPORATE AND OTHER EXPENSES, NET

     Our Corporate and Other operations include general and administrative
functions as well as other miscellaneous businesses.

  Year Ended December 31, 2003 Compared to Year Ended December 31, 2002

     For the year ended December 31, 2003, corporate and other net expenses were
$34 million lower than in 2002. The decrease was primarily due to (i) $26
million of miscellaneous balance sheet adjustments in 2002 and 2003, (ii) a $10
million increase in interest income from our unconsolidated subsidiaries, (iii)
a $6 million write-off of receivables in 2002 resulting from the sale of
substantially all of our remaining retail gas stations in 2001, and (iv) $4
million of net gains on sales of aircrafts in 2003 and 2002. Partially
offsetting these decreases was $21 million of income from the favorable
resolution of non-operating contingent obligations in 2002.

                                        37
<PAGE>

  Year Ended December 31, 2002 Compared to Year Ended December 31, 2001

     For the year ended December 31, 2002, corporate and other expenses, net
were $679 million lower than in 2001. The decrease was primarily due to $520
million of merger-related charges in 2001, in connection with our merger with El
Paso. Also contributing to the decrease in 2002 were charges of $144 million in
2001 related to increased estimates of environmental remediation and reductions
in fair value of spare parts to reflect changes in usability of spare parts
inventories based on an ongoing evaluation of our operating standards and plans
following the merger.

INTEREST AND DEBT EXPENSE

     Below is an analysis of our interest and debt expense for each of the three
years ended December 31 (in millions):

<Table>
<Caption>
                                                              2003   2002   2001
                                                              ----   ----   ----
<S>                                                           <C>    <C>    <C>
Long-term debt, including current maturities................  $412   $413   $388
Other interest..............................................     6     26     61
Commercial paper............................................    --     --      7
Capitalized interest........................................   (15)   (18)   (36)
                                                              ----   ----   ----
     Total interest and debt expense........................  $403   $421   $420
                                                              ====   ====   ====
</Table>

  Year Ended December 31, 2003 Compared to Year Ended December 31, 2002

     Interest expense on long-term debt for the year ended December 31, 2003,
was $1 million lower than in 2002 due primarily to a $69 million decrease in
interest expense resulting from the retirement of $1.7 billion of debt during
2002 and 2003 with an average interest rate of 6.52%, partially offset by a year
over year $36 million increase in interest from the debt issued by UCF and
Mohawk River Funding IV in mid-=2002. Also offsetting this decrease was $23
million of interest on $300 million of new borrowings by ANR in 2003 and $13
million of interest on $300 million of Coastal Finance I preferred securities,
which were reclassified as long-term debt as of July 1, 2003.

     Other interest for the year ended December 31, 2003 was $20 million lower
than in 2002. The decrease was primarily due to a $12 million reduction in
interest expense from the retirement of other financing obligations, a $3
million decrease due to a reduction in the factoring of receivables, and a $4
million decrease due to the termination of a marketing sales contract in 2002.

     Capitalized interest for the year ended December 31, 2003 was $3 million
lower than in 2002 primarily due to lower interest rates in 2003 as compared to
2002.

  Year Ended December 31, 2002 Compared to Year Ended December 31, 2001

     Interest expense on long-term debt for the year ended December 31, 2002,
was $25 million higher than in 2001 primarily due to a $37 million increase in
interest from the debt issued by UCF and Mohawk River Funding IV in mid-2002.
Also contributing to the increase was a $9 million increase in interest related
to the Valero lease financing loan, issued in the fourth quarter of 2001, that
was outstanding for the entire year in 2002. These increases were partially
offset by a $26 million decrease due to the retirement of approximately $1
billion of long-term debt with an average interest rate of 5.6%. The remaining
increase was primarily due to various debt issuances during 2001 that were
outstanding for the entire year in 2002.

     Interest expense on commercial paper for the year ended December 31, 2002,
was $7 million lower than in 2001. The decrease was due to the fact that we
discontinued our commercial paper program in 2002.

     Other interest for the year ended December 31, 2002, was $35 million lower
than in 2001. The decrease was primarily due to a $7 million decrease resulting
from the retirement of our other financing obligations, an $18 million decrease
in the factoring of receivables, and an $8 million decrease due to the
termination of a marketing sales contract during 2002.

                                        38
<PAGE>

     Capitalized interest for the year ended December 31, 2002, was $18 million
lower than in 2001 primarily due to lower interest rates in 2002 as compared to
2001.

AFFILIATED INTEREST EXPENSE, NET

     Affiliated interest expense, net for the year ended December 31, 2003, was
$41 million, or $32 million higher than in 2002. The increase was primarily due
to higher average advances payable to El Paso under our cash management program
in 2003. The average advance payables balance increased from $455 million in
2002 to $2,052 million in 2003. The average short-term interest rates for the
year increased from 1.9% in 2002 to 2% in 2003.

     Affiliated interest expense for the year ended December 31, 2002, was $9
million, or $37 million lower than in 2001. The decrease was primarily due to
lower short-term interest rates on decreased average advances payable to El Paso
under our cash management program. The average short-term rates for the year
decreased from 4.7% in 2001 to 1.9% in 2002. The average advance payables
balance decreased from $1 billion in 2001 to $455 million in 2002.

DISTRIBUTIONS ON PREFERRED INTERESTS OF CONSOLIDATED SUBSIDIARIES

     Distributions on preferred interests of consolidated subsidiaries for the
year ended December 31, 2003, were $18 million lower than in 2002, primarily due
to the redemption of Coastal Securities Company Limited preferred stock and the
reclassification of Coastal Finance I mandatorily redeemable preferred
securities to long-term financing obligations as a result of the adoption of
SFAS No. 150. As a result of this reclassification, we began recording the
preferred returns on these securities as interest expense rather than as
distributions of preferred interests.

     Distributions on preferred interests of consolidated subsidiaries for the
year ended December 31, 2002, were $16 million lower than in 2001, primarily due
to the redemption of all the preferred interests related to El Paso Oil & Gas
Resources, El Paso Oil & Gas Associates and Coastal Limited Ventures. The
decrease was also due to lower interest rates in 2002. Most of the preferred
returns are based on variable short-term rates, which were lower on average in
2002 than the same periods in 2001.

     For a further discussion of our borrowings and other financing activities
related to our consolidated subsidiaries, see Item 8, Financial Statements and
Supplementary Data, Note 17.

INCOME TAXES

     Income tax benefit for the year ended December 31, 2003, was $57 million
resulting in an effective tax rate of (48) percent. For the year ended December
31, 2002, income tax expense was $109 million, resulting in an effective tax
rate of 26 percent. Income tax benefit for the year ended December 31, 2001 was
$87 million resulting in an effective tax rate of 15 percent. Of the 2003
amount, $105 million related to tax benefits recorded on abandonments and sales
of certain of our foreign investments. The effective tax rate for 2003 absent
these benefits would have been 41%. Included in the 2001 benefit was a tax
charge of $106 million related to non-deductible merger charges and changes in
our estimate of additional tax liabilities. Taxes on the majority of these
estimated additional liabilities were paid in 2001. The effective tax rate for
2001 absent these charges would have been 33 percent. Differences in our
effective tax rates from the statutory tax rate of 35 percent in all years were
primarily a result of the following factors:

     - state income taxes;

     - foreign income/loss taxed at different rates;

                                        39
<PAGE>

     - non-deductible portion of merger-related costs and other tax adjustments
       to provide for revised estimated liabilities;

     - abandonments and sales of foreign investments;

     - valuation allowances;

     - depreciation, depletion and amortization; and

     - non-taxable stock dividends.

     For a reconciliation of the statutory rate to our effective tax rate, as
well as matters that could impact our future tax expense, see Item 8, Financial
Statements and Supplementary Data, Note 10.

DISCONTINUED OPERATIONS

     In 2002 and 2003, El Paso made the decision to eliminate its involvement in
our petroleum markets operations and coal mining operations and to sell the
related assets and liabilities, and, as a result, we reported these operations
as discontinued operations as of December 31, 2003 and 2002 and for the years
ended December 31, 2003, 2002 and 2001.

  Petroleum Markets Operations

     During 2003, El Paso's Board of Directors authorized the sale of
substantially all of its petroleum markets operations. Based on its intent to
dispose of these operations, we adjusted these assets to their estimated fair
value and recognized pre-tax charges during 2003 totaling approximately $1.5
billion, which included $1.1 billion related to our Aruba refinery and $264
million related to the impairment of our Eagle Point refinery. In 2003, we
completed sales of $682 million of these assets and completed an additional $905
million in early 2004. We completed the sale of substantially all of our
remaining petroleum market assets in 2004.

  Coal Mining Operations

     In late 2002 and the first quarter of 2003, we sold our coal mining
operations. These operations consisted of fifteen active underground and two
surface mines located in Kentucky, Virginia and West Virginia. Following the
authorization of the sale by El Paso's Board of Directors, we recorded
impairment charges of $185 million in our loss from discontinued operations
during 2002. We have now fully exited our coal mining operations.

     For the years ended December 31, the after-tax income (loss) related to our
discontinued operations was as follows (in millions):

<Table>
<Caption>
                                                               YEAR ENDED DECEMBER 31,
                                                              -------------------------
                                                                2003      2002    2001
                                                              --------   ------   -----
<S>                                                           <C>        <C>      <C>
Petroleum markets...........................................  $(1,298)   $(241)   $(80)
Coal mining.................................................        1     (124)     (5)
                                                              -------    -----    ----
  Total discontinued operations.............................  $(1,297)   $(365)   $(85)
                                                              =======    =====    ====
</Table>

     For the year ended December 31, 2003, we reported a loss from our
discontinued operations of $1.3 billion. This was primarily due to impairments
of long-lived assets of $1.5 billion, including $1.1 billion related to our
Aruba refinery and $264 million related to our Eagle Point refinery. In
addition, our Aruba refinery continued to generate operating losses of
approximately $82 million. These losses resulted from lower throughput at Aruba
due primarily to operational difficulties following a fire at the facility in
April 2001 and scheduled turnaround maintenance activities. Our losses were
partially offset by operating income at our Eagle Point refinery of
approximately $42 million. This income resulted from higher margins at Eagle
Point due to a widening difference between the price of the crude oil input used
by the refinery and the price we sold the refined products produced. This loss
was also partially offset by $90 million of gains recorded on the sale of our

                                        40
<PAGE>

Florida terminalling and transportation assets, asphalt facilities and chemical
facilities in 2003 and $65 million of business interruption and property damage
insurance recoveries related to the Aruba facility fire in 2001.

     For the year ended December 31, 2002, we reported a loss from discontinued
operations of $365 million. This was primarily due to operating losses of
approximately $129 million at our Aruba refinery, resulting from operational
difficulties following the fire at the facility. Also contributing to this loss
was a $185 million impairment of our coal mining operations and a $91 million
impairment of our MTBE chemical processing plant. Our losses were partially
offset by operating income at our Eagle Point refinery of approximately $97
million, resulting from higher throughput at Eagle Point during 2002 due to a
widening difference between the price of crude oil input used by the refinery
and the prices at which we sold the products produced. This loss was also
partially offset by $46 million of insurance recoveries in 2002 related to the
assets destroyed in the Aruba fire.

     For the year ended December 31, 2001, we reported a loss from discontinued
operations of $85 million. This loss included $262 million of merger-related
costs, asset impairments and other charges associated with our merger with El
Paso in 2001. See Item 8, Financial Statements and Supplementary Data, Notes 4
and 5 for a discussion of these merger-related costs and impairments. Also
contributing to the loss was an operating loss of $87 million at the Eagle Point
refinery as a result of lower margins and throughout. Partially offsetting these
losses were $97 million of insurance recoveries related to the fire at the Aruba
refinery, operating income of $126 million from our refined products and crude
oil marketing activities and $23 million of other income which includes equity
earnings and income from the lease of our Corpus Christi refinery to Valero.

                         COMMITMENTS AND CONTINGENCIES

     For a discussion of our commitments and contingencies, see Item 8,
Financial Statements and Supplementary Data, Note 18, incorporated herein by
reference.

                          CRITICAL ACCOUNTING POLICIES

     Our critical accounting policies are those accounting policies that involve
the use of complicated processes, assumptions and/or judgments in the
preparation of our financial statements. We have discussed the development and
selection of our critical accounting policies and related disclosures with the
audit committee of El Paso's Board of Directors and have identified the
following critical accounting policies for the current year.

     Accounting for Natural Gas and Oil Producing Activities.  We use the full
cost method to account for our natural gas and oil producing activities. Under
this accounting method, we capitalize substantially all of the costs incurred in
connection with the acquisition, development and exploration of natural gas and
oil reserves in full cost pools maintained by geographic areas, regardless of
whether reserves are actually discovered.

     The process of estimating natural gas and oil reserves, particularly proved
undeveloped and proved non-producing reserves, is very complex, requiring
significant judgment in the evaluation of all available geological, geophysical,
engineering and economic data. As of December 31, 2003, of our total proved
reserves, 32 percent were undeveloped and 15 percent were developed, but
non-producing. In addition, the data for a given field may also change
substantially over time as a result of numerous factors, including additional
development activity, evolving production history and a continual reassessment
of the viability of production under changing economic conditions. As a result,
material revisions to existing reserve estimates occur from time to time.
Although every reasonable effort is made to ensure that reserve estimates
reported represent the most accurate assessments possible, the subjective
decisions and variances in available data for various fields increases the
likelihood of significant changes in these estimates. If all other factors are
held constant, an increase in estimated proved reserves decreases our unit of
production depletion rate. Higher reserves can also reduce the likelihood of
ceiling test impairments. For further discussions of our reserves as well as the
restatement of our historical financial statements as a result of downward
revisions to our reserve

                                        41
<PAGE>

estimates, see Part I, Item 1, Business, under Production segment and Item 8,
Financial Statements and Supplementary Data, Notes 1 and 24.

     Under the full cost accounting method, we are required to conduct quarterly
impairment tests of our capitalized costs in each of our full cost pools. This
impairment test is referred to as a ceiling test. Our total capitalized costs,
net of related income tax effects, are limited to a ceiling based on the present
value of future net revenues using end of period spot prices, discounted at 10
percent, plus the lower of cost or fair market value of unproved properties, net
of related income tax effects. If these discounted revenues are not equal to or
greater than total capitalized costs, we are required to write-down our
capitalized costs to this level. Our ceiling test calculations include the
effects of derivative instruments we have designated as, and that qualify as,
cash flow hedges of our anticipated future natural gas and oil production.

     The ceiling test calculation assumes that the price in effect on the last
day of the quarter is held constant over the life of the reserves, even though
actual prices of natural gas and oil are volatile and change from period to
period. We attempt to realize more determinable cash flows through the use of
hedges, but a decline in commodity prices can impact the results of our ceiling
test and may result in write-downs.

     Asset Impairments.  The asset impairment accounting rules require us to
continually monitor our businesses and the business environment to determine if
an event has occurred indicating that a long-lived asset or investment may be
impaired. If an event occurs, which is a determination that involves judgment,
we then assess the expected future cash flows against which to compare the
carrying value of the asset group being evaluated, a process which also involves
judgment. We ultimately arrive at the fair value of the asset which is
determined through a combination of estimating the proceeds from the sale of the
asset, less anticipated selling costs (if we intend to sell the asset), or the
discounted estimated cash flows of the asset based on current and anticipated
future market conditions (if we intend to hold the asset). The assessment of
project level cash flows requires us to make projections and assumptions for
many years into the future for pricing, demand, competition, operating costs,
legal and regulatory issues and other factors and these variables can, and often
do, differ from our estimates. These changes can have either a positive or
negative impact on our impairment estimates. We recorded impairments of our
long-lived assets of $132 million, $36 million and $65 million during the years
ended December 31, 2003, 2002 and 2001. We recorded impairments of our
discontinued operations of $1.5 billion, $290 million and $103 million during
the years ended December 31, 2003, 2002 and 2001. Future changes in the economic
and business environment can impact our original and ongoing assessments of
potential impairments.

     Accounting for Environmental Reserves.  We accrue environmental reserves
when our assessments indicate that it is probable that a liability has been
incurred or an asset will not be recovered, and an amount can be reasonably
estimated. Estimates of our liabilities are based on currently available facts,
existing technology and presently enacted laws and regulations taking into
consideration the likely effects of societal and economic factors, and include
estimates of associated onsite, offsite and groundwater technical studies, and
legal costs. Actual results may differ from our estimates, and our estimates can
be, and often are, revised in the future, either negatively or positively,
depending upon actual outcomes or changes in expectations based on the facts
surrounding each exposure.

     As of December 31, 2003, we had accrued approximately $131 million for
environmental matters. Our reserve estimates range from approximately $131
million to approximately $252 million. Our accrual represents a combination of
two estimation methodologies. First, where the most likely outcome can be
reasonably estimated, that cost has been accrued ($49 million). Second, where
the most likely outcome cannot be estimated, a range of costs is established
($82 million to $203 million) and the lower end of the range has been accrued.

            NEW ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

     See Item 8, Financial Statements and Supplementary Data, Note 2 under New
Accounting Pronouncements Issued But Not Yet Adopted which is incorporated
herein by reference.

                                        42
<PAGE>

    RISK FACTORS AND CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR"
       PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

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

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

                         RISKS RELATED TO OUR LIQUIDITY

 WE HAVE SIGNIFICANT DEBT, WHICH HAS IMPACTED AND WILL CONTINUE TO IMPACT OUR
 FINANCIAL CONDITION, RESULTS OF OPERATIONS AND LIQUIDITY.

     We have significant debt of approximately $5 billion as of December 31,
2003 and have significant debt service and debt maturity obligations. Our
expected debt maturities for the remainder of 2004, 2005 and 2006 are $49
million, $363 million and $654 million, respectively. If our ability to generate
or access cash becomes significantly restrained, our financial condition and
future results of operations could be significantly adversely affected. See Item
8, Financial Statements and Supplementary Data, Note 16, for a further
discussion of our debt.

 A BREACH OF THE COVENANTS APPLICABLE TO OUR DEBT AND OTHER FINANCING
 OBLIGATIONS COULD AFFECT OUR ABILITY TO RAISE CAPITAL AND COULD ACCELERATE OUR
 DEBT AND OTHER FINANCING OBLIGATIONS AND THOSE OF OUR SUBSIDIARIES.

     Our debt and other financing obligations contain restrictive covenants and
cross-acceleration provisions. A breach of any of these covenants could
accelerate our long-term debt and other financing obligations and that of some
of our subsidiaries, and could preclude some of our subsidiaries from issuing
letters of credit and from borrowing under El Paso's $3 billion revolving credit
facility. If this were to occur, we may not be able to repay such debt and other
financing obligations upon such acceleration.

     Various other financing arrangements entered into by El Paso and its
subsidiaries, including us, include covenants that require us to file financial
statements within specified time periods. Non-compliance with such covenants
does not constitute an automatic event of default. Instead, such agreements are
subject to acceleration when the indenture trustee or the holders of at least 25
percent of the outstanding principal amount of any series of debt provides
notice to the issuer of non-compliance under the indenture. In that event, the
non-compliance can be cured by filing financial statements within specified
periods of time (between 30 and 90 days after receipt of notice depending on the
particular indenture) to avoid acceleration of repayment. The filing of our 2004
Forms 10-Q will cure the event of non-compliance resulting from our failure to
file financial statements. In addition, neither we nor any of El Paso's other
subsidiaries have received a notice of the default caused by our failure to file
our financial statements or the financial statements of El Paso's other
subsidiaries also impacted by the restatement. In the event of an acceleration,
we may be unable to meet our payment obligations with respect to the related
indebtedness.

                                        43
<PAGE>

  WE ARE A WHOLLY OWNED DIRECT SUBSIDIARY OF EL PASO AND ITS FINANCIAL CONDITION
  SUBJECTS US TO POTENTIAL RISKS THAT ARE BEYOND OUR CONTROL.

     El Paso has substantial control over:

     - our payment of dividends;

     - decisions on our financings and our capital raising activities;

     - mergers or other business combinations;

     - our acquisitions or dispositions of assets; and

     - our participation in El Paso's cash management program.

     El Paso may exercise such control in its interests and not necessarily in
the interests of us or the holders of our long-term debt.

     Due to our relationship with El Paso, adverse developments or announcements
concerning El Paso could adversely affect our financial condition, even if we
have not suffered any similar development. The ratings assigned to El Paso's
senior unsecured indebtedness are below investment grade, currently rated Caa1
by Moody's (with a negative outlook and under review for a possible downgrade)
and CCC+ by Standard & Poor's (with a negative outlook). Our senior unsecured
indebtedness is rated Caa1 by Moody's (with a negative outlook and under review
for a possible downgrade) and CCC+ by Standard & Poor's (with a negative
outlook). These ratings have increased our cost of capital and collateral
requirements, and could impede our access to capital markets. El Paso has
realized substantial demands on its liquidity. El Paso's current ratings are a
result, at least in part, of the outlook generally for the consolidated
businesses of El Paso and its needs for liquidity.

     El Paso has embarked on its Long Range Plan that defines El Paso's future
business, targets significant debt reduction, and establishes financial goals.
An inability to meet these objectives could adversely affect El Paso's liquidity
position, and in turn affect our financial condition.

     We participate in El Paso's cash management program, which matches cash
surplus and needs for its participating affiliates. In addition, we conduct
commercial transactions with some of our affiliates. As of December 31, 2003, we
have net payables of approximately $447 million to El Paso and its affiliates.
El Paso provides cash management and other corporate services for us. If El Paso
is unable to meet its liquidity needs, there can be no assurance that we will be
able to access cash under the cash management program, or that our affiliates
could pay their obligations to us. However, we would be required to satisfy
affiliated company payables, although we do not anticipate that El Paso will
require us to repay these payables during 2004. Our inability to access the cash
management program, recover any intercompany amounts owed to us, or a demand for
payment of our affiliated payables could adversely affect our ability to repay
our outstanding indebtedness. For a further discussion of our related party
transactions, see Part II, Item 8, Financial Statements and Supplementary Data,
Note 22.

  SOME OF OUR ASSETS ARE COLLATERAL FOR EL PASO'S $3 BILLION REVOLVING CREDIT
  FACILITY AND OTHER FINANCING TRANSACTIONS.

     Some of our subsidiaries are subsidiary guarantors of El Paso's $3 billion
revolving credit facility and other financing transactions. In connection with
their guarantees, El Paso pledged our ownership of ANR, ANR Storage, CIG, and
WIC to collateralize the $3 billion revolving credit facility and approximately
$300 million of other financing arrangements including leases, letters of credit
and other facilities. Our ownership in the above mentioned companies is subject
to change if El Paso's lenders under these facilities exercise their rights over
the collateral. If this were to occur, it could have a material adverse effect
on our financial condition.

                                        44
<PAGE>

  SOME OF OUR ASSETS ARE COLLATERAL FOR EL PASO'S WESTERN ENERGY SETTLEMENT

     One of our subsidiaries has pledged as collateral a portion of its oil and
gas properties to support the obligations of some of our affiliates to make
payments in connection with the settlement of various lawsuits arising out of
the Western Energy Crisis. If our affiliates fail to make those payments, the
properties that our subsidiary has pledged would be subject to foreclosure,
which could have a material adverse effect on our financial position and
liquidity, results of operations and cash flows.

  WE COULD BE SUBSTANTIVELY CONSOLIDATED WITH EL PASO IF EL PASO WERE FORCED TO
  SEEK PROTECTION FROM ITS CREDITORS IN BANKRUPTCY.

     If El Paso were the subject of voluntary or involuntary bankruptcy
proceedings, El Paso and its other subsidiaries and their creditors could
attempt to make claims against us, including claims to substantively consolidate
our assets and liabilities with those of El Paso and its other subsidiaries. The
equitable doctrine of substantive consolidation permits a bankruptcy court to
disregard the separateness of related entities and to consolidate and pool the
entities' assets and liabilities and treat them as though held and incurred by
one entity where the interrelationship between the entities warrants such
consolidation. We believe that any effort to substantively consolidate us with
El Paso and/or its other subsidiaries would be without merit. However, we cannot
assure you that El Paso and/or its other subsidiaries or their respective
creditors would not attempt to advance such claims in a bankruptcy proceeding
or, if advanced, how a bankruptcy court would resolve the issue. If a bankruptcy
court were to substantively consolidate us with El Paso and/or its other
subsidiaries, there could be a material adverse effect on our financial
condition and liquidity.

                 RISKS RELATED TO LEGAL AND REGULATORY MATTERS

  ONGOING LITIGATION AND INVESTIGATIONS RELATED TO OUR FINANCIAL STATEMENTS
  ASSOCIATED WITH OUR RESERVE ESTIMATES COULD SIGNIFICANTLY ADVERSELY AFFECT OUR
  BUSINESS.

     In May 2004, El Paso completed an independent investigation of the reason
for or cause of the significant revisions to our natural gas and oil reserves.
Following this investigation, we announced that we would restate our historical
financial statements for the impact of the previously announced reduction of our
proved reserve estimates. As a result of our reduction in reserve estimates,
several class action lawsuits were filed against us and several of our
subsidiaries. The reserve revisions are also the subject of investigations by
the SEC and the U.S. Attorney. These investigations and lawsuits, and possible
future claims based on these same facts, may further negatively impact our
credit ratings and place further demands on our liquidity. We cannot provide
assurance at this time that the effects and results of these or other
investigations or of the class action lawsuits will not be material to our
financial conditions, results of operations and liquidity.

  COSTS OF ENVIRONMENTAL LIABILITIES, REGULATIONS AND LITIGATION COULD EXCEED
  OUR ESTIMATES.

     Our operations are subject to various environmental laws and regulations.
These laws and regulations obligate us to install and maintain pollution
controls and to clean up various sites at which regulated materials may have
been disposed of or released. Some of these sites have been designated as
Superfund sites by the Environmental Protection Agency (EPA) under the
Comprehensive Environmental Response, Compensation and Liability Act. We are
also party to legal proceedings involving environmental matters pending in
various courts and agencies.

     Compliance with environmental laws and regulations can require significant
costs, such as costs of clean-up and damages arising out of contaminated
properties, and failure to comply with environmental laws and regulations may
result in fines and penalties being imposed. It is not possible for us to
estimate reliably the amount and timing of all future expenditures related to
environmental matters because of:

     - the uncertainties in estimating clean up costs;

     - the discovery of new sites or information;

                                        45
<PAGE>

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

     - the nature of environmental laws and regulations; and

     - the possible introduction of future environmental laws and regulations.

     Although we believe we have established appropriate reserves for
liabilities, including clean up costs, we could be required to set aside
additional reserves in the future due to these uncertainties, and these amounts
could be material. For additional information concerning our environmental
matters, see Part I, Item 3, Legal Proceedings, and Item 8, Financial Statements
and Supplementary Data, Note 18.

  COSTS OF OTHER LITIGATION MATTERS COULD EXCEED OUR ESTIMATES.

     We are involved in various lawsuits in which we or our subsidiaries have
been sued. Although we believe we have established appropriate reserves for
these liabilities, we could be required to set aside additional reserves in the
future and these amounts could be material. For additional information
concerning our litigation matters, see Part I, Item 8, Financial Statements and
Supplementary Data, Note 18.

 THE AGENCIES THAT REGULATE OUR PIPELINE BUSINESSES AND THEIR CUSTOMERS AFFECT
 OUR PROFITABILITY.

     Our pipeline businesses are regulated by the FERC, the U.S. Department of
Transportation, and various state and local regulatory agencies. Regulatory
actions taken by those agencies have the potential to adversely affect our
profitability. In particular, the FERC regulates the rates our pipelines are
permitted to charge their customers for their services. If our pipelines' tariff
rates were reduced in a future proceeding, if our pipelines' volume of business
under their currently permitted rates was decreased significantly, or if our
pipelines were required to substantially discount the rates for their services
because of competition or because of regulatory pressure, the profitability of
our pipeline businesses could be reduced.

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

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

                         RISKS RELATED TO OUR BUSINESS

  OUR OPERATIONS ARE SUBJECT TO OPERATIONAL HAZARDS AND UNINSURED RISKS.

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

     While we maintain insurance against many of these risks to the extent and
in amounts that we believe are reasonable, our financial condition and
operations could be adversely affected if a significant event occurs that is not
fully covered by insurance.

  THE SUCCESS OF OUR PIPELINE BUSINESS DEPENDS, IN PART, ON FACTORS BEYOND OUR
  CONTROL.

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

                                        46
<PAGE>

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

     - future weather conditions, including those that favor alternative energy
       sources such as hydroelectric power;

     - price competition;

     - drilling activity and supply availability of natural gas;

     - expiration and/or turn back of significant contracts;

     - service area competition;

     - changes in regulation and action of regulatory bodies;

     - credit risk of our customer base;

     - increased cost of capital;

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

     - adverse general economic conditions;

     - unfavorable movements in natural gas and liquids prices.

  THE REVENUES OF OUR PIPELINE BUSINESSES ARE GENERATED UNDER CONTRACTS THAT
  MUST BE RENEGOTIATED PERIODICALLY.

     Substantially all of our pipeline subsidiaries' revenues are generated
under contracts which expire periodically and must be renegotiated and extended
or replaced. We cannot assure that we will be able to extend or replace these
contracts when they expire or that the terms of any renegotiated contracts will
be as favorable as the existing contracts. For a further discussion of these
matters, see Part I, Item I, Business -- Regulated Business, Pipelines Segment,
Markets and Competition.

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

     - competition by other pipelines, including the proposed construction by
       other companies of additional pipeline capacity in markets served by our
       interstate pipelines;

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

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

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

     - regulatory actions.

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

  FLUCTUATIONS IN ENERGY COMMODITY PRICES COULD ADVERSELY AFFECT OUR PIPELINE
  BUSINESSES.

     Revenues generated by our transmission, storage, and processing contracts
depend on volumes and rates, both of which can be affected by the prices of
natural gas and natural gas liquids. Increased prices could result in a
reduction of the volumes transported by our customers, such as power companies
who, depending on the price of fuel, may not dispatch gas fired power plants.
Increased prices could also result from industrial plant shutdowns or load
losses to competitive fuels as well as local distribution companies' loss of
customer base. The success of our transmission, storage and processing
operations is subject to continued development of additional oil and natural gas
reserves and our ability to access additional suppliers from interconnecting
pipelines to offset the natural decline from existing wells connected to our
systems. A decline in energy prices

                                        47
<PAGE>

could precipitate a decrease in these development activities and could cause a
decrease in the volume of reserves available for transmission, storage and
processing through our systems or facilities. If natural gas prices in the
supply basins connected to our pipeline systems are higher on a delivered basis
to our off-system markets than delivered prices from other natural gas producing
regions, our ability to compete with other transporters may be negatively
impacted. Fluctuations in energy prices are caused by a number of factors,
including:

     - regional, domestic and international supply and demand;

     - availability and adequacy of transportation facilities;

     - energy legislation;

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

     - abundance of supplies of alternative energy sources; and

     - political unrest among oil producing countries.

  NATURAL GAS AND OIL PRICES ARE VOLATILE. A SUBSTANTIAL DECREASE IN NATURAL GAS
  AND OIL PRICES OR CHANGES IN BASIS DIFFERENTIALS COULD ADVERSELY AFFECT THE
  FINANCIAL RESULTS OF OUR EXPLORATION AND PRODUCTION BUSINESS.

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

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

     - commodity processing, gathering and transportation availability;

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

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

     - domestic governmental regulations and taxes;

     - the price and availability of alternative fuel sources;

     - weather conditions;

     - market uncertainty;

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

     - worldwide economic conditions; and

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

     Further, because approximately 69 percent of our proved reserves at
December 31, 2003 were natural gas reserves, we are substantially more sensitive
to changes in natural gas prices than we are to changes in oil prices. Declines
in natural gas and oil prices would not only reduce revenue, but could reduce
the amount of natural gas and oil that we can produce economically and, as a
result, could adversely affect the financial results of our production business.
Changes in natural gas and oil prices have a significant impact on the
calculation of our full cost ceiling test. A significant decline in natural gas
and oil prices could result in a downward revision of our reserves and a
write-down of the carrying value of our natural gas and oil properties, which
could be substantial and would negatively impact our net income and
stockholder's equity.

                                        48
<PAGE>

 THE SUCCESS OF OUR NATURAL GAS AND OIL EXPLORATION AND PRODUCTION BUSINESSES IS
 DEPENDENT, IN PART, ON FACTORS THAT ARE BEYOND OUR CONTROL.

     In addition to prices, the performance of our natural gas and oil
exploration and production businesses is dependent, in part, upon a number of
factors that we cannot control, including:

     - the results of future drilling activity, including exploratory programs
       that recently have not been successful;

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

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

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

     - future drilling, production and development costs, including drilling rig
       rates and oil field services costs;

     - 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;

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

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

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

     Our affiliate, El Paso Production Holding Company (El Paso Production), is
a wholly owned direct subsidiary of El Paso. El Paso Production, through its
subsidiaries engages in the exploration for and the acquisition, development and
production of natural gas and oil, primarily in North America. We and El Paso
Production do not have an agreement regarding the allocation of business
opportunities.

     In addition, our officers, directors and personnel also provide services to
El Paso Production and its subsidiaries pursuant to our shared services
arrangement and therefore share their time and services between us and El Paso
Production. These persons may therefore have conflicts of interest between us
and El Paso Production.

  OUR NATURAL GAS AND OIL DRILLING AND PRODUCING OPERATIONS INVOLVE MANY RISKS
  AND MAY NOT BE PROFITABLE.

     Our operations are subject to all the risks normally incident to the
operation and development of natural gas and oil properties and the drilling of
natural gas and oil wells, including well blowouts, cratering and explosions,
pipe failure, fires, formations with abnormal pressures, uncontrollable flows of
natural gas, oil, brine or well fluids, release of contaminants into the
environment and other environmental hazards and risks. The nature of the risks
is such that some liabilities could exceed our insurance policy limits, or, as
in the case of environmental fines and penalties, cannot be insured. As a
result, we could incur substantial costs that could adversely affect our future
results of operations, cash flows or financial condition.

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

                                        49
<PAGE>

  ESTIMATING OUR RESERVES, PRODUCTION AND FUTURE NET CASH FLOW IS DIFFICULT.

     Estimating quantities of proved natural gas and oil reserves is a complex
process that involves significant interpretations and assumptions. It requires
interpretations of available technical data and various estimates, including
estimates based upon assumptions relating to economic factors, such as future
commodity prices, production costs, severance and excise taxes, capital
expenditures and workover and remedial costs, and the assumed effect of
governmental regulation. As a result, our reserve estimates are inherently
imprecise. Also, the use of a 10 percent discount factor for estimating the
value of our reserves, as prescribed by the SEC, may not necessarily represent
the most appropriate discount factor, given actual interest rates and risks to
which our production business or the natural gas and oil industry, in general,
are subject. Any significant variations from the interpretations or assumptions
used in our estimates or changes of conditions could cause the estimated
quantities and net present value of our reserves to differ materially.

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

     As of December 31, 2003, approximately 32 percent of our estimated proved
reserves were undeveloped. Recovery of undeveloped reserves requires significant
capital expenditures and successful drilling operations. The reserve data
assumes that we can and will make these expenditures and conduct these
operations successfully, but future events, including commodity price changes,
may cause these assumptions to change. In addition, estimates of undeveloped
reserves and proved but non-producing reserves are subject to greater
uncertainties than estimates of producing reserves.

  THE SUCCESS OF OUR POWER GENERATION ACTIVITIES DEPENDS, IN PART, ON MANY
  FACTORS BEYOND OUR CONTROL.

     The success of our remaining domestic and international power projects
could be adversely affected by factors beyond our control, including:

     - alternative sources and supplies of energy becoming available due to new
       technologies and interest in self generation and cogeneration;

     - increases in the costs of generation, including increases in fuel costs;

     - uncertain regulatory conditions resulting from the ongoing deregulation
       of the electric industry in the U.S. and in foreign jurisdictions;

     - our ability to negotiate successfully and enter into, advantageous power
       purchase and supply agreements;

     - the possibility of a reduction in the projected rate of growth in
       electricity usage as a result of factors such as regional economic
       conditions, excessive reserve margins and the implementation of
       conservation programs;

     - risks incidental to the operation and maintenance of power generation
       facilities;

     - the inability of customers to pay amounts owed under power purchase
       agreements;

     - the increasing price volatility due to deregulation and changes in
       commodity trading practices; and

     - over-capacity of generation in markets served by the power plants we own
       or in which we have an interest.

                                        50
<PAGE>

  OUR FOREIGN OPERATIONS AND INVESTMENTS INVOLVE SPECIAL RISKS.

     Our activities in areas outside the U.S. are subject to the risks inherent
in foreign operations, including:

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

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

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

                                        51
<PAGE>

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     We are exposed to several market risks in our normal business activities.
Market risk is the potential loss that may result from market changes associated
with an existing or forecasted financial or commodity transaction. The types of
market risks we are exposed to and examples of each are:

     - Commodity Price Risk

        - Natural gas prices change, impacting the forecasted sale of natural
          gas in our Production segment;

        - Price spreads between natural gas and natural gas liquids change,
          making the natural gas liquids we produce in our Field Services
          segment less valuable;

        - Electricity and natural gas prices change, affecting the value of our
          power contracts held in our Merchant Energy 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; and

        - 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.

     We manage these risks by entering into contractual commitments involving
physical or financial settlements that attempt to limit the amount of risk or
opportunity related to future market movements, primarily related to movements
in natural gas prices. Our risk management activities typically involve the use
of forward contracts and financial swaps, many of which are derivative financial
instruments. A discussion of our accounting policies for derivative instruments
is included in Item 8, Financial Statements and Supplementary Data, Notes 2 and
13.

COMMODITY PRICE RISK

     Our principal commodity price risks exist in our Production segment. Our
Production segment attempts to mitigate commodity price risk and to stabilize
cash flows associated with its forecasted sales of its natural gas and oil
production through the use of derivative natural gas and oil swap contracts
entered into with other El Paso affiliates. The table below presents the
hypothetical sensitivity to changes in fair values arising from immediate
selected potential changes in the quoted market prices of the derivative
commodity instruments used to mitigate these market risks that were outstanding
at December 31, 2003 and 2002. Any gain or loss on these derivative commodity
instruments would be substantially offset by a corresponding gain or loss on the
hedged commodity positions, which are not included in the table.

<Table>
<Caption>
                                                               10 PERCENT INCREASE      10 PERCENT DECREASE
                                                             -----------------------   ---------------------
                                                FAIR VALUE   FAIR VALUE   (DECREASE)   FAIR VALUE   INCREASE
                                                ----------   ----------   ----------   ----------   --------
                                                                       (IN MILLIONS)
<S>                                             <C>          <C>          <C>          <C>          <C>
Impact of changes in commodity prices on
  derivative commodity instruments
  December 31, 2003...........................    $(123)       $(147)        $(24)        $(99)       $24
  December 31, 2002...........................    $(144)       $(190)        $(46)        $(98)       $46
</Table>

     The derivatives described above do not hedge all of our commodity price
risk related to our forecasted sales of our natural gas production and as a
result, we are subject to commodity price risks on our remaining forecasted
natural gas production.

INTEREST RATE RISK

  Debt

     Many of our debt-related financial instruments and project financing
arrangements are sensitive to changes in interest rates. The table below shows
the maturity of the carrying amounts and related

                                        52
<PAGE>

weighted-average interest rates on our interest-bearing securities, by expected
maturity dates and the fair values of those securities. As of December 31, 2003
and 2002, the carrying amounts of short-term borrowings are representative of
fair values because of the short-term maturity of these instruments. The fair
value of the long-term securities has been estimated based on quoted market
prices for the same or similar issues.

<Table>
<Caption>
                                                        DECEMBER 31, 2003
                               -------------------------------------------------------------------   DECEMBER 31, 2002
                                      EXPECTED FISCAL YEAR OF MATURITY OF CARRYING AMOUNTS           ------------------
                               -------------------------------------------------------------------   CARRYING    FAIR
                               2004   2005   2006   2007   2008   THEREAFTER   TOTAL    FAIR VALUE   AMOUNTS     VALUE
                               ----   ----   ----   ----   ----   ----------   ------   ----------   --------   -------
                                                      (DOLLARS IN MILLIONS)
<S>                            <C>    <C>    <C>    <C>    <C>    <C>          <C>      <C>          <C>        <C>
LIABILITIES:
Long-term debt and other
  financing obligations,
  including current
  portion -- fixed rate......  $300   $251   $541   $ 51   $474     $3,463     $5,080     $4,992      $4,648    $3,931
      Average interest
        rate.................   6.9%   9.3%   7.2%   7.9%   7.2%       8.0%
Long-term debt, including
  current portion -- variable
  rate.......................  $ 12   $111   $111   $  7                       $  241     $  241      $  706    $  706
      Average interest
        rate.................   2.1%   4.0%   4.0%   2.1%
</Table>

  Derivatives from Power Contract Restructuring Activities

     Derivatives associated with our power contract restructuring business in
our Merchant Energy segment are valued using estimated future market power
prices and a discount rate that considers the appropriate U.S. Treasury rate
plus a credit spread specific to the contract's counterparty. We make
adjustments to this discount rate when we believe that market changes in the
rates result in changes in value that can be realized in a current transaction
between willing parties. Since September 30, 2002, in order to provide for
market risk, we have not reflected the increase in value that would result from
decreases in U.S. Treasury rates because we believe the resulting increase in
the value of these non-trading derivatives could not be realized in a current
transaction between willing parties. Had we reflected the actual U.S. Treasury
yields as of December 31, 2003 in our valuation, the value of our third party
non-trading derivatives would have been higher by approximately $87 million. As
of December 31, 2003, a ten percent increase or decrease in the discount rate
used to value third-party positions would result in an increase (decrease) in
the fair value of these derivative contracts of $(37) million and $39 million.
As a result of the sale of UCF and Mohawk River Funding IV in 2004, our
sensitivity to interest rate changes in these derivatives was eliminated.

FOREIGN CURRENCY EXCHANGE RATE RISK

     Several of our international power plants in Asia and Central America have
long-term power sales contracts that are denominated in the local country's
currencies. As a result, we are subject to foreign currency exchange risk
related to these power sales contracts. We do not believe that this exposure is
material to our operations and have not chosen to mitigate this exposure.

                                        53
<PAGE>

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                         INDEX TO FINANCIAL STATEMENTS

     Below is an index to the financial statements and notes contained in Item
8, Financial Statements and Supplementary Data.

<Table>
<Caption>
                                                              PAGE
                                                              ----
<S>                                                           <C>
Consolidated Statements of Income -- Restated...............   55
Consolidated Balance Sheets -- Restated.....................   56
Consolidated Statements of Cash Flows -- Restated...........   58
Consolidated Statements of Stockholder's
  Equity -- Restated........................................   59
Consolidated Statements of Comprehensive
  Income -- Restated........................................   60
Notes to Consolidated Financial Statements -- Restated......   61
  1.   Restatement of Historical Financial Statements and
        Liquidity...........................................   61
  2.   Summary of Significant Accounting Policies...........   67
  3.   Divestitures.........................................   76
  4.   Merger-Related Costs.................................   78
  5.   Loss (Gain) on Long-Lived Assets.....................   79
  6.   Accounting Changes...................................   80
  7.   Ceiling Test Charges.................................   80
  8.   Other Income and Other Expenses......................   81
  9.   Income Taxes.........................................   81
  10.  Discontinued Operations..............................   84
  11.  Financial Instruments................................   86
  12.  Price Risk Management Activities.....................   87
  13.  Inventory............................................   90
  14.  Regulatory Assets and Liabilities....................   90
  15.  Property, Plant and Equipment........................   90
  16.  Debt, Other Financing Obligations and Other Credit
        Facilities..........................................   91
  17.  Preferred Interests of Consolidated Subsidiaries.....   94
  18.  Commitments and Contingencies........................   94
  19.  Retirement Benefits..................................   98
  20.  Segment Information..................................  102
  21.  Supplemental Cash Flow Information...................  106
  22.  Investments in and Advances to Unconsolidated
        Affiliates and Transactions with Related Parties....  107
  23.  Supplemental Selected Quarterly Financial Information
        (Unaudited).........................................  111
  24.  Supplemental Natural Gas and Oil Operations
        (Unaudited).........................................  112
Report of Independent Registered Public Accounting Firm.....  120
Schedule II -- Valuation and Qualifying Accounts............  121
</Table>

                                        54
<PAGE>

                              EL PASO CGP COMPANY

                       CONSOLIDATED STATEMENTS OF INCOME
                                 (IN MILLIONS)

<Table>
<Caption>
                                                                   YEAR ENDED DECEMBER 31,
                                                              ---------------------------------
                                                                           2002         2001
                                                               2003     (RESTATED)   (RESTATED)
                                                              -------   ----------   ----------
<S>                                                           <C>       <C>          <C>
Operating revenues
  Pipelines.................................................  $   918     $  934       $1,054
  Production................................................      910      1,258        1,783
  Field Services............................................      356        460          894
  Merchant Energy...........................................      238      1,204           43
  Corporate and eliminations................................      (48)       (30)         190
                                                              -------     ------       ------
                                                                2,374      3,826        3,964
                                                              -------     ------       ------
Operating expenses
  Cost of products and services.............................      509      1,050        1,121
  Operation and maintenance.................................      540        777          819
  Merger-related costs......................................       --         --          787
  Depreciation, depletion and amortization..................      517        630          836
  Ceiling test charges......................................      109        521          537
  Loss (gain) on long-lived assets..........................       97         (7)          69
  Taxes, other than income taxes............................       82         78          141
                                                              -------     ------       ------
                                                                1,854      3,049        4,310
                                                              -------     ------       ------
Operating income (loss).....................................      520        777         (346)
Earnings (losses) from unconsolidated affiliates............      (12)       113          220
Other income................................................       66         70           81
Other expenses..............................................        5        (70)         (18)
Interest and debt expense...................................     (403)      (421)        (420)
Affiliated interest expense, net............................      (41)        (9)         (46)
Distributions on preferred interests of consolidated
  subsidiaries..............................................      (17)       (35)         (51)
                                                              -------     ------       ------
Income (loss) before income taxes...........................      118        425         (580)
Income taxes................................................      (57)       109          (87)
                                                              -------     ------       ------
Income (loss) from continuing operations....................      175        316         (493)
Discontinued operations, net of income taxes................   (1,297)      (365)         (85)
Extraordinary items, net of income taxes....................       --         --          (11)
Cumulative effect of accounting changes, net of income
  taxes.....................................................      (12)        14           --
                                                              -------     ------       ------
Net loss....................................................  $(1,134)    $  (35)      $ (589)
                                                              =======     ======       ======
</Table>

                            See accompanying notes.

                                        55
<PAGE>

                              EL PASO CGP COMPANY

                          CONSOLIDATED BALANCE SHEETS
                      (IN MILLIONS, EXCEPT SHARE AMOUNTS)

<Table>
<Caption>
                                                                  DECEMBER 31,
                                                              --------------------
                                                                           2002
                                                               2003     (RESTATED)
                                                              -------   ----------
<S>                                                           <C>       <C>
                                      ASSETS
Current assets
  Cash and cash equivalents.................................  $   150    $   128
  Accounts and notes receivable
     Customer, net of allowance of $37 in 2003 and $21 in
      2002..................................................      309        400
     Affiliates.............................................      442        521
     Other..................................................       87        133
  Inventory.................................................       58         61
  Assets from price risk management activities..............       97        102
  Assets of discontinued operations.........................    1,369      2,154
  Other.....................................................      138        162
                                                              -------    -------
          Total current assets..............................    2,650      3,661
                                                              -------    -------
Property, plant and equipment, at cost
  Natural gas and oil properties, at full cost..............    8,304      7,744
  Pipelines.................................................    6,478      6,522
  Power facilities..........................................      372        460
  Gathering and processing systems..........................      151        279
  Other.....................................................      119         93
                                                              -------    -------
                                                               15,424     15,098

  Less accumulated depreciation, depletion and
     amortization...........................................    8,678      8,471
                                                              -------    -------
          Total property, plant and equipment, net..........    6,746      6,627
                                                              -------    -------
Other assets
  Investments in unconsolidated affiliates..................    1,312      1,505
  Assets from price risk management activities..............      845        956
  Goodwill and other intangible assets, net.................      413        475
  Assets of discontinued operations.........................       --      1,911
  Other.....................................................      443        420
                                                              -------    -------
                                                                3,013      5,267
                                                              -------    -------

          Total assets......................................  $12,409    $15,555
                                                              =======    =======
</Table>

                            See accompanying notes.

                                        56
<PAGE>
                              EL PASO CGP COMPANY

                   CONSOLIDATED BALANCE SHEETS -- (CONTINUED)
                      (IN MILLIONS, EXCEPT SHARE AMOUNTS)

<Table>
<Caption>
                                                                  DECEMBER 31,
                                                              --------------------
                                                                           2002
                                                               2003     (RESTATED)
                                                              -------   ----------
<S>                                                           <C>       <C>
                       LIABILITIES AND STOCKHOLDER'S EQUITY

Current liabilities
  Accounts payable
     Trade..................................................  $   197    $   208
     Affiliates.............................................      110         87
     Other..................................................      238        261
  Short-term financing obligations, including current
     maturities.............................................      310        369
  Notes payable to affiliates...............................      906      2,374
  Liabilities from price risk management activities.........       43        216
  Liabilities of discontinued operations....................      658      1,373
  Other.....................................................      320        273
                                                              -------    -------
          Total current liabilities.........................    2,782      5,161
                                                              -------    -------
Long-term financing obligations, less current maturities....    5,011      4,985
                                                              -------    -------
Other
  Liabilities from price risk management activities.........       81         24
  Deferred income taxes.....................................      732      1,193
  Liabilities of discontinued operations....................       --         87
  Other.....................................................      351        239
                                                              -------    -------
                                                                1,164      1,543
                                                              -------    -------
Commitments and contingencies
Securities of subsidiaries
  Preferred interests of consolidated subsidiaries..........       --        400
  Minority interests of consolidated subsidiaries...........      107        114
                                                              -------    -------
                                                                  107        514
                                                              -------    -------
Stockholder's equity
  Common stock, par value $1 per share; authorized and
     issued 1,000 shares....................................       --         --
  Additional paid-in capital................................    3,136      1,616
  Retained earnings.........................................      224      1,875
  Accumulated other comprehensive loss......................      (15)      (139)
                                                              -------    -------
          Total stockholder's equity........................    3,345      3,352
                                                              -------    -------
          Total liabilities and stockholder's equity........  $12,409    $15,555
                                                              =======    =======
</Table>

                            See accompanying notes.

                                        57
<PAGE>

                              EL PASO CGP COMPANY

                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                                 (IN MILLIONS)

<Table>
<Caption>
                                                                      YEAR ENDED DECEMBER 31,
                                                              ---------------------------------------
                                                                            2002            2001
                                                               2003     (RESTATED)(1)   (RESTATED)(1)
                                                              -------   -------------   -------------
<S>                                                           <C>       <C>             <C>
Cash flows from operating activities
  Net loss..................................................  $(1,134)     $   (35)        $  (589)
    Less net loss from discontinued operations, net of
      income taxes..........................................   (1,297)        (365)            (85)
                                                              -------      -------         -------
  Net income (loss) from continuing operations..............      163          330            (504)
  Adjustments to reconcile net income (loss) to net cash
    from operating activities
    Depreciation, depletion and amortization................      517          630             836
    Ceiling test charges....................................      109          521             537
    (Earnings) losses from unconsolidated affiliates,
      adjusted for cash distributions.......................      102           28            (103)
    Deferred income tax expense (benefit)...................     (139)         137            (137)
    Loss (gain) on long-lived assets........................       97           (7)             69
    Extraordinary items.....................................       --           --              11
    Cumulative effect of accounting changes.................       12          (14)             --
    Non-cash portion of merger-related costs and changes in
      estimates.............................................       --           --             858
    Other non-cash income items.............................       (3)          46              27
    Asset and liability changes
      Accounts and notes receivable.........................      438         (469)           (448)
      Accounts payable......................................      (91)        (330)            497
      Inventory.............................................       --           54               5
      Changes in trading price risk management activities...       22         (480)             25
      Other asset and liability changes
        Assets..............................................      (73)         178             485
        Liabilities.........................................       30          (98)           (397)
                                                              -------      -------         -------
    Cash provided by continuing operations..................    1,184          526           1,761
    Cash provided by (used in) discontinued operations......      (40)        (271)            191
                                                              -------      -------         -------
        Net cash provided by operating activities...........    1,144          255           1,952
                                                              -------      -------         -------
Cash flows from investing activities
  Additions to property, plant and equipment................     (985)      (1,394)         (2,077)
  Equity investments........................................       (9)         (45)           (133)
  Net proceeds from the sale of assets......................      324        1,518             274
  Net proceeds from the sale of investments.................       60          167             347
  Net change in restricted cash.............................      (18)         (59)             --
  Repayment of notes receivable from affiliates.............       (8)        (102)             18
  Net cash paid for acquisitions, net of cash acquired......       --           45            (232)
  Other.....................................................      (35)         (64)              1
                                                              -------      -------         -------
    Cash provided by (used in) continuing operations........     (671)          66          (1,802)
    Cash provided by (used in) discontinued operations......      427         (163)           (212)
                                                              -------      -------         -------
        Net cash used in investing activities...............     (244)         (97)         (2,014)
                                                              -------      -------         -------
Cash flows from financing activities
  Net repayments under commercial paper and short-term
    credit facilities.......................................       --          (30)           (765)
  Capital contribution from parent company..................    1,500           --              --
  Net proceeds from the issuance of long-term debt and other
    financing obligations...................................      288          882             340
  Payments to retire long-term debt and other financing
    obligations.............................................     (638)      (1,240)           (572)
  Payments to preferred interest and minority interest
    holders.................................................     (100)        (510)             --
  Dividends paid............................................     (517)          --             (13)
  Net proceeds from issuance of minority interests in
    subsidiaries............................................       --           33             139
  Net change in notes payable to unconsolidated
    affiliates..............................................       (7)         (56)             --
  Net change in affiliated advances payable.................   (1,404)       1,317             889
  Contributions from (distributions to) discontinued
    operations..............................................      387         (995)             99
  Other.....................................................       --           (6)              8
                                                              -------      -------         -------
    Cash provided by (used in) continuing operations........     (491)        (605)            125
    Cash provided by (used in) discontinued operations......     (387)         444              15
                                                              -------      -------         -------
        Net cash provided by (used in) financing
          activities........................................     (878)        (161)            140
                                                              -------      -------         -------
Change in cash and cash equivalents.........................       22           (3)             78
  Less change in cash and cash equivalents related to
    discontinued operations.................................       --           10              (6)
                                                              -------      -------         -------
  Change in cash and cash equivalents from continuing
    operations..............................................       22          (13)             84
Cash and cash equivalents
  Beginning of period.......................................      128          141              57
                                                              -------      -------         -------
  End of period.............................................  $   150      $   128         $   141
                                                              =======      =======         =======
</Table>

---------------
(1) Cash flows from continuing operating, investing and financing activities
    were restated. However, the total cash flows from continuing operations for
    2002 were unaffected.

                            See accompanying notes.

                                        58
<PAGE>

                              EL PASO CGP COMPANY

                CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY

<Table>
<Caption>
                                                                  FOR THE YEARS ENDED DECEMBER 31,
                                                       -------------------------------------------------------
                                                                                2002               2001
                                                             2003            (RESTATED)         (RESTATED)
                                                       -----------------   ---------------   -----------------
                                                       SHARES    AMOUNT    SHARES   AMOUNT    SHARES    AMOUNT
                                                       -------   -------   ------   ------   --------   ------
                                                          (IN THOUSANDS OF SHARES AND MILLIONS OF DOLLARS)
<S>                                                    <C>       <C>       <C>      <C>      <C>        <C>
Preferred stock, par value 33 1/3c per share,
  authorized 50,000 shares cumulative convertible
  preferred
  $1.19, Series A:
    Balance at beginning of year.....................       --   $    --      --    $  --          52   $   --
    Converted to El Paso common stock................       --        --      --       --         (52)      --
                                                       -------   -------    ----    ------   --------   ------
    Balance at end of year...........................       --        --      --       --          --       --
                                                       =======   =======    ====    ======   ========   ======
  $1.83, Series B:
    Balance at beginning of year.....................       --        --      --       --          51       --
    Converted to El Paso common stock................       --        --      --       --         (51)
                                                       -------   -------    ----    ------   --------   ------
    Balance at end of year...........................       --        --      --       --          --       --
                                                       =======   =======    ====    ======   ========   ======
  $5.00, Series C:
    Balance at beginning of year.....................       --        --      --       --          26       --
    Converted to El Paso common stock................       --        --      --       --         (26)      --
                                                       -------   -------    ----    ------   --------   ------
    Balance at end of year...........................       --        --      --       --          --       --
                                                       =======   =======    ====    ======   ========   ======
Class A common stock, par value 33 1/3c per share,
  authorized 2,700 shares
  Balance at beginning of year.......................       --        --      --       --         311       --
  Converted to El Paso common stock..................       --        --      --       --        (311)      --
                                                       -------   -------    ----    ------   --------   ------
  Balance at end of year.............................       --        --      --       --          --       --
                                                       =======   =======    ====    ======   ========   ======
Common stock, par value 33 1/3c per share, authorized
  500,000 shares
  Balance at beginning of year.......................        1        --       1       --     219,605       73
  Exercise of stock options..........................       --        --      --       --          86       --
  Conversion to El Paso common stock.................       --        --      --       --    (219,690)     (73)
                                                       -------   -------    ----    ------   --------   ------
  Balance at end of year.............................        1        --       1       --           1       --
                                                       =======   =======    ====    ======   ========   ======
Additional paid-in capital
  Balance at beginning of year.......................              1,616            1,305                1,044
  Capital contribution from El Paso..................              1,524              309                  278
  Other..............................................                 (4)               2                  (17)
                                                                 -------            ------              ------
  Balance at end of year.............................              3,136            1,616                1,305
                                                                 =======            ======              ======
Retained earnings
  Balance at beginning of year.......................              1,875            1,910                2,499
  Net loss for period................................             (1,134)             (35)                (589)
  Dividends to parent................................               (517)              --                   --
                                                                 -------            ------              ------
  Balance at end of year.............................                224            1,875                1,910
                                                                 =======            ======              ======
Accumulated other comprehensive income (loss)
  Balance at beginning of year.......................               (139)             283                   (8)
  Other comprehensive income (loss)..................                124             (422)                 291
                                                                 -------            ------              ------
  Balance at end of year.............................                (15)            (139)                 283
                                                                 =======            ======              ======
Treasury stock, at cost
  Balance at beginning of year.......................       --        --      --       --      (4,395)    (132)
  Retirement of treasury shares......................                                           4,395      132
                                                       -------   -------    ----    ------   --------   ------
  Balance at end of year.............................       --        --      --       --          --       --
                                                       =======   -------    ====    ------   ========   ------
         Total.......................................            $ 3,345            $3,352              $3,498
                                                                 =======            ======              ======
</Table>

                            See accompanying notes.

                                        59
<PAGE>

                              EL PASO CGP COMPANY

                CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
                                 (IN MILLIONS)

<Table>
<Caption>
                                                                   YEAR ENDED DECEMBER 31,
                                                              ---------------------------------
                                                                           2002         2001
                                                               2003     (RESTATED)   (RESTATED)
                                                              -------   ----------   ----------
<S>                                                           <C>       <C>          <C>
Net loss....................................................  $(1,134)    $ (35)       $(589)
                                                              -------     -----        -----
  Foreign currency translation adjustments..................      112       (14)         (27)
  Minimum pension liability accrual (net of income tax of $1
     in 2003 and $7 in 2002)................................       (5)      (12)          --
  Net gains (losses) from cash flow hedging activities:
     Cumulative effect of transition adjustment (net of
       income tax of $248)..................................                 --         (459)
     Unrealized mark-to-market gains (losses) arising during
       period (net of income tax of $24 in 2003, $140 in
       2002 and $398 in 2001)...............................      (42)     (240)         728
     Reclassification adjustments for changes in initial
       value to settlement date (net of income tax of $34 in
       2003, $87 in 2002 and $27 in 2001)...................       59      (156)          49
                                                              -------     -----        -----
       Other comprehensive income (loss)....................      124      (422)         291
                                                              -------     -----        -----
Comprehensive loss..........................................  $(1,010)    $(457)       $(298)
                                                              =======     =====        =====
</Table>

                            See accompanying notes.

                                        60
<PAGE>

                              EL PASO CGP COMPANY

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. RESTATEMENT OF HISTORICAL FINANCIAL STATEMENTS AND LIQUIDITY

                 RESTATEMENT OF HISTORICAL FINANCIAL STATEMENTS

     In February 2004, we completed the December 31, 2003 reserve estimation
process for the proved natural gas and oil reserves in our Production segment.
At the same time, our independent reserve engineers completed their estimates of
our proved reserves. Overall, our internally prepared reserve estimates were
within 5 percent of the total of the estimates of our independent reserve
engineers. The proved reserve estimates as of December 31, 2003 indicated a 1.0
Tcfe or approximate 47 percent downward revision in our proved natural gas and
oil reserves was needed. Given the size of this revision, the Audit Committee of
El Paso's Board of Directors initiated an independent investigation to be
conducted by an outside law firm to determine the factors that contributed to
this significant downward revision. The scope of the investigation included (1)
assessing the reasons for the downward revisions, (2) evaluating the internal
controls associated with the booking of reserves, (3) suggesting any
recommendations with regard to improvements in internal controls and processes
and (4) recommending any remedial actions that may be required. The
investigation included the completion of more than 200 interviews and the review
of more than 100,000 documents. Based on the investigation results, we concluded
that a material portion of the negative reserve revisions should have been
reflected in periods prior to 2003 and would require a revision of the
historical reserve estimates included in our supplemental natural gas and oil
operations data. Quantities of proven natural gas and oil reserves are used in
determining financial statement amounts, including ceiling test charges,
depletion expense and gains and losses on natural gas and oil property sales.
The revision of our historical reserve estimates required the restatement of the
financial statement information derived from these estimates. The investigation
found that certain personnel used aggressive, and at times, unsupportable
methods to book proved reserves. In some instances, certain personnel provided
historical proved reserve estimates that they knew or should have known were
incorrect at the time they were reported. The investigation also found that we
did not, in some cases, maintain adequate documentation and records to support
historically booked reserves. Based on the results of the investigation, we (a)
reviewed alternatives with respect to the method or methods to be used to
restate our reserve amounts in prior periods and (b) assessed and implemented
remedial actions related to our management structure, internal control
environment and internal control processes.

  Restatement Methodology

     Because of concerns over our historical documentation supporting reserves
and the aggressive, and sometimes unsupportable methods that were used by
personnel in booking proved reserves, the methodology we adopted to restate our
reserves for the years ended December 31, 2001 and 2002 and the nine months
ended September 30, 2003, was a reserve reconstruction approach. Under this
method, we utilized the estimated proved reserves as of December 31, 2003 that
were derived from our review completed in February 2004, and then determined
historical reserves by adjusting these reserves for actual historical production
data and other known data to determine the reconstructed estimates of reserves
at each period end. The basic assumption underlying our methodology was that the
December 31, 2003 reserve report represented the most recent, reliable and
available information and was our best estimate of proved reserves. That report,
therefore, became the basis of our historical reserve reconstruction. We then
created a reconstruction process by adding actual production volumes in prior
periods, on a well by well basis, with adjustments for assets sold (the more
significant sales were re-evaluated by one of our independent reserve engineers
since the proved reserves that were sold were not in the December 31, 2003
reserve report and needed to be re-evaluated given the findings in the
investigation) and other known information during the period such as cost and
capital spending during the restatement period.

     We applied the approach described above back to December 31, 2000. However,
for periods prior to December 31, 2000, which were necessary to determine the
impact of the reserve restatement on beginning stockholder's equity as of
January 1, 2001, we did not have access to the necessary detailed electronic
records

                                        61
<PAGE>

to apply this methodology. This was due, in part to some of the documentation
issues identified in the investigation, and numerous changes in personnel
immediately following past mergers, which impacted our ability to locate that
historical documentation. As a result, we used our December 31, 2000 reserve
levels determined by the reconstruction approach described above as the
foundation for estimating reserves and related cash flows (for ceiling test
purposes) for periods prior to December 31, 2000. This estimation approach
involved the use of a "reserve over production ratio" based on the reconstructed
December 31, 2000 reserve estimates. The reserve over production ratio provided
the estimated life of reserves based on production levels. We applied that ratio
to the actual historical period production levels to calculate estimated
historical reserves for each period. In determining the reserve over production
ratio to use for each period, historical prices were considered since at
different pricing levels, varying levels of reserves are economical to produce,
which also impacted capital cost, operating cost and revenue assumptions in
determining cash flows that would be derived from reserves.

     Overall, our restatement approach allowed us to re-calculate reasonable
proved reserve estimates at the end of each quarter over the last five years.
Once we determined the historical reserve levels, we then calculated our
estimated future net cash flows at the end of each quarter. These revised
quarterly proved reserves and the resulting discounted net cash flows were then
used to perform the ceiling test, calculate our depreciation, depletion and
amortization rate, income taxes and evaluate gain or loss recognition on natural
gas and oil property sales for each quarter. Finally, we assessed the adequacy
of our overall approach based on historical prices and historically capitalized
costs leading up to the earliest period in which our restatement was performed.
Based on that assessment, we believe the amount recorded as a retained earnings
adjustment on January 1, 1999 reasonably reflects the financial statement impact
of our restated reserve levels that would have occurred prior to that time.

     We believe the approach used to restate our historical reserves is a
reasonable approach and is appropriate in these circumstances. It is based on a
current, thoroughly reviewed and well documented reserve study and reflects
actual historical data. However, it does have some limitations. First, the
restated reserve levels and reported earnings do not incorporate normal positive
or negative revisions in reserves that could have resulted for reasons such as
mechanical failures, changes in estimates or the impact of actual drilling
results on proved undeveloped reserves. These are normally occurring changes to
reserves estimates that, because of the methodology we used, will not be
reflected during the year they actually occurred. Rather, they will be part of
our beginning retained earnings adjustments. Overall, we believe their effects
on our reported results would be similar. Second, because we had to use a
variation of the methodology for the years 1999 and 2000, to determine the
impact on our retained earnings at January 1, 2001, the restated reserves for
these periods may not be comparable to the reserve amounts that would have
resulted from an actual reconstruction and none of the periods would be
identical to a completely re-engineered approach. Overall, however, we believe
our approach, given the results of the investigation and documentation issues
discussed above, provides a reasonable approach to revising our historical
reserve data that presents our related historical financial results in
accordance with generally accepted accounting principles.

     We also considered other restatement methodologies such as re-engineering
specific production and reserve areas to determine, in hindsight, where previous
estimates should have been adjusted in specific periods. We rejected this
approach for several reasons. First, this method would not have produced, in our
view, a more accurate result than the method we adopted, particularly given our
concerns with respect to the timing of when the reserves were originally
recorded. Second, it was very difficult to make reasonable assessments of how
specific reserves should have been booked at a particular time without being
influenced by subsequent data, especially in light of the assumptions that had
already been made in the reserve estimation process. Third, the investigation
identified that (a) a large number of personnel were responsible for making
reserve estimates and that there was not a consistent or centralized approach
used in the reserve estimation process, including the assumptions used in the
process or the documentation generated in support of these assumptions and (b)
there was a lack of controls over inputs into the reserve data base. As a result
of such factors, the integrity of the data could not be reasonably relied upon
for a detailed re-engineering of reserves. Finally, the findings of the
independent investigation identified that there was inadequate detailed
historical, technical documentation to support the booking of certain reported
reserves. Consequently, without such

                                        62
<PAGE>

detailed documentation, it would be extremely difficult, and in some cases
impossible, to determine with precision the appropriate time that specific
reserves should have been removed from the proved reserves category.

     Our reserve restatement methodology resulted in the following revisions to
our proved natural gas and oil reserves (Bcfe) (Unaudited):

<Table>
<Caption>
                                                           AS OF DECEMBER 31,
                                     ---------------------------------------------------------------
                                            2002                  2001                  2000
                                     -------------------   -------------------   -------------------
                                        AS         AS         AS         AS         AS         AS
                                     REPORTED   RESTATED   REPORTED   RESTATED   REPORTED   RESTATED
                                     --------   --------   --------   --------   --------   --------
<S>                                  <C>        <C>        <C>        <C>        <C>        <C>
U.S.
  Onshore..........................   1,413        758      3,415      1,499      3,512      1,422
  Offshore.........................     400        205        532        233        820        371
  Coal Seam........................     153         95         51         39         77         58
                                      -----      -----      -----      -----      -----      -----
Total U.S. ........................   1,966      1,058      3,998      1,771      4,409      1,851
                                      -----      -----      -----      -----      -----      -----
International
  Canada...........................     167        110        252        113        190         33
  Brazil...........................     100         --         87         --        120         --
  Other............................      52          5         --         --         --         --
                                      -----      -----      -----      -----      -----      -----
  Total International..............     319        115        339        113        310         33
                                      -----      -----      -----      -----      -----      -----
Natural Gas Systems................      --         --        183        183        175        175
                                      -----      -----      -----      -----      -----      -----
Total Worldwide....................   2,285      1,173      4,520      2,067      4,894      2,059
                                      =====      =====      =====      =====      =====      =====
</Table>

     The restatement of our proved reserves also impacted previously reported
items in our supplemental information on our natural gas and oil activities,
including the classification of costs incurred in natural gas and oil activities
between exploration or development cost. For a further discussion of our natural
gas and oil reserves, see Note 25, Supplemental Natural Gas and Oil Operations.
Also, for a discussion of a restatement related to our original classification
of a contribution by El Paso of interests in one of its subsidiaries to us, see
Note 22.

  Financial Impact of Restatement

     The total cumulative impact of the restatement that affected our
stockholder's equity as of September 30, 2003 was a reduction of approximately
$1.1 billion, which includes a reduction in beginning stockholder's equity as of
January 1, 2001 of $1.1 billion. Of the adjustment to beginning stockholder's
equity $11 million, net of tax, related to higher depreciation, depletion and
amortization expense in 2000, $80 million, net of tax, to higher ceiling test
charges offset partially by lower depreciation, depletion and amortization
expense in 1999 and $1 billion, net of tax, related to the impacts of the
reserve revision restatement on beginning stockholder's equity as of January 1,
1999. We did not reconstruct our reserves to periods prior to December 31, 1998.
We believe our approach and the five year period through which our
reconstruction was performed was reasonable in light of the circumstances
surrounding our restatement.

     As to the individual financial statement line items, our historical
financial statements for the years ended December 31, 2002 and 2001, for each of
the quarters in those years and for each quarter and the first nine months of
2003 reflect the effects of the restatement on (i) the calculation of our
historical depletion expense and its effect on our cumulative effect of
accounting changes for our asset retirement obligations, (ii) the amount of our
quarterly full cost ceiling test charges on amounts capitalized in our natural
gas and oil full cost pools, (iii) the amounts of gains or losses recorded on
long-lived assets sold, and (iv) the amounts of income taxes. We did not amend
our annual report on Form 10-K for the years ended December 31, 2002 and 2001,
or our quarterly reports on Form 10-Q for any periods prior to December 31,
2003, and the financial statements and related financial information contained
in those reports should no longer be relied upon. A summary of the effects of
the restatement on reported amounts for the years ended December 31, 2002 and
2001, and for the quarterly periods during the three year period ended December
31, 2003 is presented below. The quarterly

                                        63
<PAGE>

period information for 2001 is being provided for supplemental purposes only.
Also, the information in the quarterly data below represents only those income
statement and balance sheet line items affected by the restatement. For
additional supplemental quarterly information, see Note 23.

<Table>
<Caption>
                                                                  YEAR ENDED            YEAR ENDED
                                                               DECEMBER 31, 2002     DECEMBER 31, 2001
                                                              -------------------   -------------------
                                                                 AS         AS         AS         AS
                                                              REPORTED   RESTATED   REPORTED   RESTATED
                                                              --------   --------   --------   --------
                                                                            (IN MILLIONS)
<S>                                                           <C>        <C>        <C>        <C>
INCOME STATEMENT:
Depreciation, depletion and amortization...................    $  608     $  630     $  632     $  836
Ceiling test charges(1)....................................       245        521        115        537
Loss (gain) on long-lived assets...........................       694         (7)        69         69
Operating income (loss)....................................       463        777        280       (346)
Income taxes (benefit).....................................       (47)       109        139        (87)
Net loss...................................................      (283)       (35)      (188)      (589)
BALANCE SHEET:
Property, plant and equipment, net.........................    $8,284     $6,627     $9,903     $7,631
Investments in unconsolidated affiliates...................     1,528      1,505      1,821      1,798
Stockholder's equity(2)....................................     4,300      3,352      4,970      3,498
</Table>

---------------

(1) Ceiling test charges for each period were calculated based on a comparison
    of the overall capitalized costs to the estimated future cash flows from
    reserves using our restated reserve levels at then current prices and
    adjusting these cash flows for the impact of hedges. These calculations were
    performed quarterly for each period restated.

(2) The impact on stockholder's equity for the year ended December 31, 2001
    includes the restatement impacts on depreciation, depletion and amortization
    and ceiling test charges during that year, as well as the adjustment to
    opening retained earnings for the effects of the restatement on years prior
    to 2001.

<Table>
<Caption>
                                                                   QUARTERS ENDED (UNAUDITED)
                                                 ---------------------------------------------------------------
                                                                                                SEPTEMBER 30,
                                                   MARCH 31, 2003         JUNE 30, 2003             2003
                                                 -------------------   -------------------   -------------------
                                                    AS         AS         AS         AS         AS         AS
                                                 REPORTED   RESTATED   REPORTED   RESTATED   REPORTED   RESTATED
                                                 --------   --------   --------   --------   --------   --------
                                                                          (IN MILLIONS)
<S>                                              <C>        <C>        <C>        <C>        <C>        <C>
Depreciation, depletion and amortization(1)....    $137       $128      $ 143      $ 129       $137       $129
Ceiling test charges...........................      --          1         --         20         --         80
Operating income(1)............................     268        276        213        207        117         45
Income taxes (benefit).........................      12         72         77         13         (5)       (30)
Cumulative effect of accounting changes, net of
  income taxes.................................     (21)       (12)        --         --         --         --
Net loss(1)....................................     (55)       (98)      (942)      (884)       (23)       (69)
</Table>

---------------

(1) Our "as reported" depreciation, depletion and amortization, operating
    income, and income taxes (benefit) differ from those amounts originally
    included in our March 31, 2003 Form 10-Q by $(13) million, $262 million and
    $29 million due to reclassifications associated with our discontinued
    operations and other minor reclassifications, which had no impact on
    previously reported net income.

<Table>
<Caption>
                                                                 QUARTERS ENDED (UNAUDITED)
                                ---------------------------------------------------------------------------------------------
                                   MARCH 31, 2002           JUNE 30, 2002        SEPTEMBER 30, 2002       DECEMBER 31, 2002
                                ---------------------   ---------------------   ---------------------   ---------------------
                                   AS          AS          AS          AS          AS          AS          AS          AS
                                REPORTED    RESTATED    REPORTED    RESTATED    REPORTED    RESTATED    REPORTED    RESTATED
                                ---------   ---------   ---------   ---------   ---------   ---------   ---------   ---------
                                                                        (IN MILLIONS)
<S>                             <C>         <C>         <C>         <C>         <C>         <C>         <C>         <C>
Depreciation, depletion and
  amortization................   $  181      $  194       $148        $ 158       $129        $137        $ 150       $141
Ceiling test charges..........       10           4        233          514         --          --            2          3
Loss (gain) on long-lived
  assets......................      (11)        (11)       (10)         (10)         1           1          714         13
Operating income (loss).......      693         597         94         (198)       165         156         (489)       222
Income taxes (benefit)........      162         158          5           (1)        22         (62)        (236)        14
Net income (loss).............      394         392        (88)        (373)       (56)         19         (533)       (73)
</Table>

                                        64
<PAGE>

<Table>
<Caption>
                                                                 QUARTERS ENDED (UNAUDITED)
                                ---------------------------------------------------------------------------------------------
                                   MARCH 31, 2001           JUNE 30, 2001        SEPTEMBER 30, 2001       DECEMBER 31, 2001
                                ---------------------   ---------------------   ---------------------   ---------------------
                                   AS          AS          AS          AS          AS          AS          AS          AS
                                REPORTED    RESTATED    REPORTED    RESTATED    REPORTED    RESTATED    REPORTED    RESTATED
                                ---------   ---------   ---------   ---------   ---------   ---------   ---------   ---------
                                                                        (IN MILLIONS)
<S>                             <C>         <C>         <C>         <C>         <C>         <C>         <C>         <C>
Depreciation, depletion and
  amortization................   $  144      $  173       $167       $  212       $163        $ 246       $158        $205
Ceiling test charges..........       --         115         --           66        115          346         --          10
Operating income (loss).......     (278)       (422)        53          (58)       145         (169)       360         303
Income taxes (benefit)........      (25)        (73)        (6)        (245)         6          117        164         114
Net income (loss).............     (347)       (443)       (65)          63         36         (389)       188         180
</Table>

     The restatement of our historical reserve estimates and our historical
financial information derived from those estimates has resulted in a delay in
the filing of these annual financial statements and has resulted or will result
in a delay in the filing of our Forms 10-Q for the quarterly periods ended March
31, 2004, June 30, 2004 and September 30, 2004. Furthermore, these restatements,
and ongoing reviews and investigations by the SEC, the U.S. Attorney and other
regulators into these restatements, could further limit or delay our ability to
quickly access the capital markets in the near term.

     The restatement will result in a lower depletion rate and reduced exposure
to ceiling test charges in the future than would have been the case absent the
restatement. In addition, the restatement did not have any impact on our
consolidated cash flows.

                                LIQUIDITY UPDATE

     We rely on cash generated from our internal operations and loans from El
Paso through its cash management program as our primary sources of liquidity, as
well as asset sales and capital contributions from El Paso. We expect that our
future funding for working capital needs, capital expenditures and debt service
will continue to be provided from some or all of these sources. Each of these
sources is impacted by factors that influence the overall amount of cash
generated by us and the capital available to us. For example, cash generated by
our business operations may be impacted by changes in commodity prices or
demands for our commodities or services due to weather patterns, competition
from other providers or alternative energy sources. Cash generated by future
asset sales may depend on the overall economic conditions of the industries
served by these assets, the condition and location of the assets and the number
of interested buyers.

     El Paso is a significant source of liquidity to us, and we participate in
its cash management program. Under this program, depending on whether we have
short-term cash surpluses or requirements, we either provide cash to El Paso or
El Paso provides cash to us. We have historically and consistently borrowed cash
from El Paso under this program. Currently, one of our subsidiaries, CIG, is not
advancing funds to El Paso via the cash management program based on its expected
cash needs. On December 31, 2003, El Paso authorized a capital contribution of
$1.5 billion to us and as of December 31, 2003, we had a note payable to El Paso
of $906 million related to this program. This note is classified as a current
liability in our balance sheet because it is due upon demand. Our ability to
rely on advances from El Paso can be impacted by its credit standing, its
requirement to repay debt and other financing obligations, and the cash demands
from other parts of its business. If El Paso were unable to meet its liquidity
needs, we would not have access to this source of liquidity. Furthermore, we
would be required to repay affiliated company payables, if demanded. However, we
do not anticipate that El Paso will require us to repay these payables during
2004.

     In February 2004 El Paso completed the December 31, 2003 reserve estimation
process for its proved natural gas and oil reserves, which included reserves in
our Production segment. As a result of this review, El Paso announced that it
was significantly reducing its proved natural gas and oil reserve estimates,
including our reserves. After an investigation into this matter, El Paso
concluded that a restatement of its historical financial statements, as well as
ours, was required.

     El Paso believes that a material restatement of its financial statements
would have constituted events of default under its $3 billion revolving credit
facility and various other financing transactions; specifically under the
provisions related to representations and warranties on the accuracy of its
historical financial statements

                                        65
<PAGE>

and on El Paso's debt to capitalization ratio. During 2004, El Paso received
several waivers on its $3 billion revolving credit facility and these other
financing transactions to address the restatement. These waivers continue to be
effective. El Paso also received an extension of time with various lenders until
November 30, 2004 to file its first and second quarter 2004 Forms 10-Q, which it
expects to meet. If El Paso is unable to file its Forms 10-Q by that date and it
is not able to negotiate an additional extension of the filing deadline, the $3
billion revolving credit facility and various other financing transactions could
be accelerated. As part of obtaining its waivers, El Paso also amended various
provisions of the $3 billion revolving credit facility, including provisions
related to events of default and limitations on the ability of El Paso and its
subsidiaries to repay indebtedness scheduled to mature after June 30, 2005.
Although two of our subsidiaries (ANR and CIG) are eligible to borrow under El
Paso's $3 billion revolving credit facility, they do not have any borrowings or
letters of credit outstanding under that facility. Based upon a review of the
provisions of our indentures and the financing agreements, we believe that a
default on El Paso's $3 billion revolving credit facility would not result in an
event of default under our other debt agreements unless such default resulted in
the acceleration of El Paso's $3 billion revolving credit facility or other
transactions collateralized by the same assets and our subsidiaries failed to
perform their obligations under their guarantees of such debt.

     Various other financing arrangements entered into by El Paso and it's
subsidiaries, including us, include covenants that require us to file financial
statements within specified time periods. Non-compliance with these covenants
does not constitute an automatic event of default. Instead, such agreements are
subject to acceleration when the indenture trustee or the holders of at least 25
percent of the outstanding principal amount of any series of debt provides
notice to the issuer of non-compliance under the indenture. In that event, the
default can be cured by filing financial statements within specified periods of
time (between 30 and 90 days after receipt of notice depending on the particular
indenture) to avoid acceleration of repayment. The filing of our first and
second quarter 2004 Forms 10-Q will cure the events of non-compliance resulting
from our failure to file financial statements. We have not received a notice of
the default caused by our failure to file our financial statements. In the event
of an acceleration, we may be unable to meet our payment obligations with
respect to the related indebtedness.

     If El Paso were subject to voluntary or involuntary bankruptcy proceedings,
El Paso and its other subsidiaries and their creditors could attempt to make
claims against us, including claims to substantively consolidate our assets and
liabilities with those of El Paso and its other subsidiaries. We believe that
claims to substantively consolidate us with El Paso and/or its other
subsidiaries would be without merit. However, there is no assurance that El Paso
and/or its other subsidiaries or their creditors would not advance such a claim
in a bankruptcy proceeding. If we were to be substantively consolidated in a
bankruptcy proceeding with El Paso and/or its other subsidiaries, it could have
a material adverse effect on our financial condition and our liquidity.

     Some of our subsidiaries are subsidiary guarantors of El Paso's $3 billion
revolving credit facility and other financing transactions. In connection with
their guarantees, El Paso pledged our ownership of ANR, ANR Storage, CIG, and
WIC to collateralize the $3 billion revolving credit facility and approximately
$300 million of other financing arrangements including leases, letters of credit
and other facilities. Our ownership in the above mentioned companies is subject
to change if El Paso's lenders under these facilities exercise their rights over
the collateral. If this were to occur, it could have a material adverse effect
on our financial condition. In addition, one of our subsidiaries has pledged as
collateral a portion of its natural gas and oil properties to support the
obligations of some of our affiliates to make payments in connection with the
settlement of various lawsuits arising out of the Western Energy Crisis. If our
affiliates fail to make those payments, the properties that our subsidiary has
pledged would be subject to foreclosure, which could have a material adverse
effect on our financial position, results of operations and cash flows.

     We have cross-acceleration provisions in our long-term debt-agreements
which, if triggered, could result in the acceleration of our debt. The most
restrictive indenture has a cross-acceleration threshold of $5 million. The
acceleration of our long-term debt would adversely affect our liquidity position
and, in turn, our financial condition.

                                        66
<PAGE>

     We believe we will generate sufficient funds through our operations, asset
sales, financing activities and advances from El Paso to meet all of our cash
needs.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

  Basis of Presentation

     Our consolidated financial statements include the accounts of all
majority-owned, controlled subsidiaries after the elimination of all significant
intercompany accounts and transactions. Our results for all periods presented
reflect our petroleum markets and coal mining businesses as discontinued
operations. Additionally, our financial statements for prior periods include
reclassifications that were made to conform to the current year presentation.
Those reclassifications did not impact our reported net income or stockholder's
equity.

  Principles of Consolidation

     We consolidate entities when we have the ability to control the operating
and financial decisions and policies of that entity. Where we can exert
significant influence over, but do not control, those policies and decisions, we
apply the equity method of accounting. We use the cost method of accounting
where we are unable to exert significant influence over the entity. The
determination of our ability to control or exert significant influence over an
entity involves the use of judgment of the extent of our control or influence
and that of the other equity owners or participants of the entity. Discussed
below in New Accounting Pronouncements Issued But Not Yet Adopted is a standard
that, once effective, will impact our consolidation principles.

  Use of Estimates

     The preparation of financial statements in conformity with accounting
principles generally accepted in the U.S. requires the use of estimates and
assumptions that affect the amounts we report as assets, liabilities, revenues
and expenses and our disclosures in these financial statements. Actual results
can, and often do, differ from those estimates.

 Accounting for Regulated Operations

     Our interstate natural gas pipelines and storage operations are subject to
the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and
the Natural Gas Policy Act of 1978. Effective December 31, 2003, CIG and WIC
re-applied the regulatory accounting principles prescribed under Statement of
Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of
Certain Types of Regulation (see Note 15 for a further discussion). ANR
discontinued the application of SFAS No. 71 in 1996. The accounting required by
SFAS No. 71 differs from the accounting required for businesses that do not
apply its provisions. Transactions that are generally recorded differently as a
result of applying regulatory accounting requirements include the capitalization
of an equity return component on regulated capital projects, postretirement
employee benefit plans, and other costs included in, or expected to be included
in, future rates.

     We perform an annual review to assess the applicability of the provisions
of SFAS No. 71 to our financial statements, the outcome of which could result in
the re-application of this accounting in some of our regulated systems or the
discontinuance of this accounting in others.

  Cash and Cash Equivalents

     We consider short-term investments with an original maturity of less than
three months to be cash equivalents.

     We maintain cash on deposit with banks and insurance companies that is
pledged for a particular use or restricted to support a potential liability. We
classify these balances as restricted cash in other current or non-current
assets in our balance sheet based on when we expect this cash to be used. As of
December 31, 2003 we had $36 million of restricted cash in other current assets
and $43 million in other

                                        67
<PAGE>

non-current assets and as of December 31, 2002, we had $28 million of restricted
cash in other current assets and $32 million in other non-current assets.

  Allowance for Doubtful Accounts

     We establish provisions for losses on accounts and notes receivable and for
natural gas imbalances due from shippers and operators if we determine that we
will not collect all or part of the outstanding balance. We regularly review
collectibility and establish or adjust our allowance as necessary using the
specific identification method.

  Inventory

     Our inventory consists of materials and supplies and natural gas in
storage. We classify all inventory as current or non-current based on whether it
will be sold or used in the normal operating cycle of the assets, to which it
relates, which is typically within the next twelve months. We use the average
cost method to account for our inventories. We value all inventory at the lower
of its cost or market value.

  Property, Plant and Equipment

     Our property, plant and equipment is recorded at its original cost of
construction or, upon acquisition, at the fair value of the assets acquired. We
capitalize direct costs, such as labor and materials, and indirect costs, such
as overhead, interest and in our regulated businesses that apply the provisions
of SFAS No. 71, an equity return component. We capitalize the major units of
property replacements or improvements and expense minor items.

     The following table presents our property, plant and equipment by type,
depreciation method and depreciable lives:

<Table>
<Caption>
                          TYPE                                METHOD      DEPRECIABLE LIVES
                          ----                                ------      -----------------
                                                                             (IN YEARS)
<S>                                                        <C>            <C>
Regulated interstate systems
  SFAS No. 71(1).........................................  Composite          3-51
  Non-SFAS No. 71........................................  Straight-line      1-64

Unregulated systems
  Transmission and storage facilities....................  Straight-line      59
  Power facilities.......................................  Straight-line      7-20
  Gathering and processing systems.......................  Straight-line      4-40
  Transportation equipment...............................  Straight-line      3-5
  Buildings and improvements.............................  Straight-line     14-40
  Office and miscellaneous equipment.....................  Straight-line      3-10
</Table>

---------------

(1) For our regulated interstate systems that apply SFAS No. 71, we use the
    composite (group) method to depreciate property, plant and equipment. Under
    this method, assets with similar useful lives and other characteristics are
    grouped and depreciated as one asset. We apply the depreciation rate
    approved in our rate settlements to the total cost of the group until its
    net book value equals its salvage value. We re-evaluate depreciation rates
    each time we redevelop our transportation rates when we file with the FERC
    for an increase or decrease in rates.

     When we retire regulated property, plant and equipment accounted for under
SFAS No. 71, we charge accumulated depreciation and amortization for the
original cost, plus the cost to remove, sell or dispose, less its salvage value.
We do not recognize a gain or loss unless we sell an entire operating unit. We
include gains or losses on dispositions of operating units in income. When we
retire regulated property, plant and equipment not accounted for under SFAS No.
71 and non-regulated properties, we reduce property, plant and equipment for its
original cost, less accumulated depreciation and salvage value, with any
remaining gain or loss recorded in income.

     We capitalize a carrying cost on funds invested in our construction of
long-lived assets. This carrying cost consists of (i) an interest cost on the
investment financed by debt, which applies to both regulated and

                                        68
<PAGE>

non-regulated transmission businesses and (ii) a return on the investment
financed by equity, which only applies to regulated transmission businesses that
apply SFAS No. 71. The debt portion is calculated based on the average cost of
debt. Amounts capitalized related to interest costs on debt during the years
ended December 31, 2003, 2002 and 2001, were $15 million, $18 million and $36
million. These amounts are included as a reduction of interest expense in our
income statements. The equity portion is calculated using the most recent FERC
approved equity rate of return. These amounts are included as other
non-operating income on our income statement. Capitalized carrying costs for
debt and equity financed construction are reflected as an increase in the cost
of the asset on our balance sheet.

  Asset Impairments

     We apply the provisions of SFAS No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, to account for asset impairments. Under this
standard, we evaluate an asset for impairment when events or circumstances
indicate that its carrying value may not be recovered. These events include
market declines, changes in the manner in which we intend to use an asset,
decisions to sell an asset and adverse changes in the legal or business
environment such as adverse actions by regulators. When an event occurs, we
evaluate the recoverability of the asset's carrying value based on its ability
to generate future cash flows on an undiscounted basis. When we decide to exit
or sell a long-lived asset or group of assets, we adjust the carrying value of
these assets downward, if necessary, to the estimated sales price, less costs to
sell. Our fair value estimates are generally based on preliminary market data
obtained through the early stages of the sales process and an analysis of
expected discounted cash flows. The magnitude of any impairments are impacted by
a number of factors, including the nature of the assets to be sold and our
established time frame for completing the sales, among other factors. We also
reclassify the asset or assets as either held-for-sale or as discontinued
operations, depending on, among other criteria, whether we will have any
continuing involvement in the cash flows of those assets after they are sold.

  Natural Gas and Oil Properties

     We use the full cost method to account for our natural gas and oil
properties. Under the full cost method, substantially all productive and
nonproductive costs incurred in connection with the acquisition, development and
exploration of natural gas and oil reserves are capitalized. These capitalized
amounts include the costs of all unproved properties, internal costs directly
related to acquisition, development and exploration activities, asset retirement
costs and capitalized interest. This method differs from the successful efforts
method of accounting for these activities. The primary differences between these
two methods are the treatment of exploratory dry hole costs. These costs are
generally expensed under successful efforts when the determination is made that
measurable reserves do not exist. Geological and geophysical costs are also
expensed under the successful efforts method. Under the full cost method, both
dry hole costs and geological and geophysical costs are capitalized into the
full cost pool which is then periodically assessed for recoverability as
discussed below.

     We amortize capitalized costs using the unit of production method over the
life of our proved reserves. Capitalized costs associated with unproved
properties are excluded from the amortizable base until these properties are
evaluated. Future development costs and dismantlement, restoration and
abandonment costs, net of estimated salvage values, are included in the
amortizable base. Beginning January 1, 2003, we began capitalizing asset
retirement costs associated with proved developed natural gas and oil reserves
into our full cost pool, pursuant to the adoption of SFAS No. 143, Accounting
for Asset Retirement Obligations as discussed below.

     Our capitalized costs, net of related income tax effects, are limited to a
ceiling based on the present value of future net revenues using end of period
spot prices discounted at 10 percent, plus the lower of cost or fair market
value of unproved properties, net of related income tax effects. If these
discounted revenues are not equal to or greater than total capitalized costs, we
are required to write-down our capitalized costs to this level. We perform this
ceiling test calculation each quarter. Any required write-downs are included in
our income statement as ceiling test charges. Our ceiling test calculations
include the effects of derivative instruments we have designated as, and that
qualify as, cash flow hedges of our anticipated future natural gas and oil
production.

                                        69
<PAGE>

     When we sell or convey interests (including net profits interests) in our
natural gas and oil properties, we reduce our reserves for the amount
attributable to the sold or conveyed interest. We do not recognize a gain or
loss on sales of our natural gas and oil properties, unless those sales would
significantly alter the relationship between capitalized costs and proved
reserves. We treat sales proceeds on non-significant sales as an adjustment to
the cost of our properties.

  Goodwill and Other Intangible Assets

     Our intangible assets consist of goodwill resulting from acquisitions and
other intangible assets. We apply SFAS No. 141, Business Combinations, and SFAS
No. 142, Goodwill and Other Intangible Assets, to account for these intangibles.
Under these standards, we recognize goodwill separately from other intangible
assets. In addition, goodwill and intangibles that have indefinite lives are not
amortized. Also, goodwill and indefinite lived intangible assets are
periodically tested for impairment, at least annually, and whenever an event
occurs that indicates that an impairment may have occurred. We adopted these
standards on January 1, 2002 and stopped amortizing goodwill. The initial
impairment tests we performed as of January 1, 2002 indicated no impairment of
our goodwill.

     The net carrying amounts of our goodwill as of December 31, 2003 and 2002,
and the changes in the net carrying amounts of goodwill for the years ended
December 31, 2003 and 2002 for each of our segments are as follows:

<Table>
<Caption>
                                                                            FIELD
                                                  PIPELINES   PRODUCTION   SERVICES    TOTAL
                                                  ---------   ----------   --------   -------
                                                            (IN MILLIONS)
<S>                                               <C>         <C>          <C>        <C>
Balances as of January 1, 2002..................    $413         $ 61        $ 14      $488
  Impairments of goodwill.......................      --           --         (14)      (14)
  Other changes.................................      --            1          --         1
                                                    ----         ----        ----      ----
Balances as of December 31, 2002................     413           62          --       475
                                                    ----         ----        ----      ----
  Impairments of goodwill.......................      --          (75)         --       (75)
  Other changes.................................      --           13          --        13
                                                    ----         ----        ----      ----
Balances as of December 31, 2003................    $413         $ --        $ --      $413
                                                    ====         ====        ====      ====
</Table>

     In 2003, our Production segment impaired $75 million of goodwill which
resulted from its decision to reduce its involvement in its Canadian production
operations. In 2002, we impaired $14 million of goodwill associated with our
Field Services segment, which resulted from the sale of assets in this segment
during 2002 and early 2003.

     Our other intangible assets consist of customer lists and other
miscellaneous intangible assets. We amortize all intangible assets on a
straight-line basis over their estimated useful life. The following are the
gross carrying amounts and accumulated amortization of our other intangible
assets as of December 31:

<Table>
<Caption>
                                                              2003    2002
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
Intangible assets subject to amortization...................  $ 31    $ 31
Accumulated amortization....................................   (23)    (12)
                                                              ----    ----
                                                              $  8    $ 19
                                                              ====    ====
</Table>

     Amortization expense of our intangible assets subject to amortization was
$1 million and $7 million for the years ended December 31, 2003 and 2002. For
the year ended December 31, 2001, amortization of all intangible assets,
including goodwill, was $32 million. Based on the current amount of intangible
assets subject to amortization, our estimated amortization expense is
approximately $1 million for each of the next five years. These amounts may vary
as a result of future acquisitions, dispositions and any recorded impairments.

                                        70
<PAGE>

     The following table presents our loss before extraordinary items and the
cumulative effect of accounting changes and net loss for the year ended December
31, 2001, as if goodwill had not been amortized during that year compared to
results as actually reported:

<Table>
<Caption>
                                                                  DECEMBER 31,
                                                              ---------------------
                                                                            2001
                                                                2001     PRO FORMA
                                                              RESTATED   (RESTATED)
                                                              --------   ----------
                                                                  (IN MILLIONS)
<S>                                                           <C>        <C>
Loss before extraordinary items and cumulative effect of
  accounting changes........................................   $(578)      $(578)
Amortization of goodwill....................................      --          16
                                                               -----       -----
Adjusted loss before extraordinary items and cumulative
  effect of accounting changes..............................   $(578)      $(562)
                                                               =====       =====
Net loss....................................................   $(589)      $(589)
Amortization of goodwill....................................      --          16
                                                               -----       -----
Adjusted net loss...........................................   $(589)      $(573)
                                                               =====       =====
</Table>

  Pension and Other Postretirement Benefits

     El Paso maintains several pension and other postretirement benefit plans.
These plans require us to make contributions to fund the benefits to be paid out
under the plans. These contributions are invested until the benefits are paid
out to plan participants. We record benefit expense related to these plans in
our income statement. This benefit expense is a function of many factors
including benefits earned during the year by plan participants (which is a
function of the employee's salary, the level of benefits provided under the
plan, actuarial assumptions, and the passage of time), expected return on plan
assets and recognition of certain deferred gains and losses as well as plan
amendments.

     We compare the benefits earned, or the accumulated benefit obligation, to
the plan's fair value of assets on an annual basis. To the extent the plan's
accumulated benefit obligation exceeds the fair value of plan assets, we record
a minimum pension liability in our balance sheet equal to the difference in
these two amounts. We do not record an additional minimum liability if it is
less than the liability already accrued for the plan. If this difference is
greater than the pension liability recorded on our balance sheet, however, we
record an additional liability and an amount to other comprehensive loss, net of
income taxes, on our financial statements.

  Revenue Recognition

     Our business segments provide a number of services and sell a variety of
products. Our revenue recognition policies by segment are as follows:

     Pipelines revenues.  Our Pipelines segment derives revenues primarily from
transportation and storage services. We also derive revenue from sales of
natural gas. For our transportation and storage services, we recognize
reservation revenues on firm contracted capacity over the contract period
regardless of the amount that is actually used. For interruptible or volumetric
based services, and for revenues under natural gas sales contracts we record
revenues when we complete the delivery of natural gas to the agreed upon
delivery point and when natural gas is injected or withdrawn from the storage
facility. Revenues in all services are generally based on the thermal quantity
of gas delivered or subscribed at a price specified in the contract or tariff.
We are subject to FERC regulations and, as a result, revenues we collect may be
refunded in a final order of a pending or future rate proceeding or as a result
of a rate settlement. We establish reserves for these potential refunds.

     Production revenues.  Our Production segment derives revenues primarily
through physical sales of natural gas, oil and natural gas liquids produced.
Revenues from sales of these products are recorded upon the passage of title
using the sales method, net of any royalty interests or other profit interests
in the produced

                                        71
<PAGE>

product. When actual natural gas sales volumes exceed our entitled share of
sales volumes, an overproduced imbalance occurs. To the extent the overproduced
imbalance exceeds our share of the remaining estimated proved natural gas
reserves for a given property, we record a liability. Costs associated with the
transportation and delivery of our production are included in cost of sales.

     Field Services revenues.  Our Field Services segment derives revenues
principally from processing and gathering services and through the sale of
commodities that are retained from providing these services. There are two
general types of service: fee-based and make-whole. For fee-based services we
recognize revenues at the time service is rendered based upon the volume of gas
gathered, treated or processed at the contracted fee. For make-whole services,
our fee consists of retainage of natural gas liquids and other by-products that
are a result of processing, and we recognize revenues on these services at the
time we sell these products, which generally coincides with when we provide the
service.

     Merchant Energy revenues.  Our Merchant Energy segment derives revenues
from a number of sources including physical sales of power and the management of
its derivative contracts. Our derivative transactions are recorded at their fair
value, and changes in their fair value are reflected in operating revenues. See
a discussion of our income recognition policies on derivatives below under Price
Risk Management Activities. Revenues on physical sales are recognized at the
time the commodity is delivered and are based on the volumes delivered and the
contracted or market price.

  Environmental Costs and Other Contingencies

     We record liabilities when our environmental assessments indicate that
remediation efforts are probable, and the costs can be reasonably estimated. We
recognize a current period expense for the liability when clean-up efforts do
not benefit future periods. We capitalize costs that benefit more than one
accounting period, except in instances where separate agreements or legal or
regulatory guidelines dictate otherwise. Estimates of our liabilities are based
on currently available facts, existing technology and presently enacted laws and
regulations taking into consideration the likely effects of other societal and
economic factors, and include estimates of associated legal costs. These amounts
also consider prior experience in remediating contaminated sites, other
companies' clean-up experience and data released by the EPA or other
organizations. These estimates are subject to revision in future periods based
on actual costs or new circumstances and are included in our balance sheet in
other current and long-term liabilities at their undiscounted amounts. We
evaluate recoveries from insurance coverage or government sponsored programs
separately from our liability and, when recovery is assured, we record and
report an asset separately from the associated liability in our financial
statements.

     We recognize liabilities for other contingencies when we have an exposure
that, when fully analyzed, indicates it is both probable that an asset has been
impaired or that a liability has been incurred and the amount of impairment or
loss can be reasonably estimated. Funds spent to remedy these contingencies are
charged against a reserve, if one exists, or expensed. When a range of probable
loss can be estimated, we accrue the most likely amount or at least the minimum
of the range of probable loss.

  Price Risk Management Activities

     Our price risk management activities primarily consist of derivatives
entered into to hedge the commodity price risks on our natural gas and oil
production and derivatives related to our power contract restructuring business.

     We account for all derivative instruments under SFAS No. 133, Accounting
for Derivative Instruments and Hedging Activities. Under SFAS No. 133,
derivatives are reflected in our balance sheet at their fair value as assets and
liabilities from price risk management activities. We classify our derivatives
as either current or non-current assets or liabilities based on their
anticipated settlement date. We net derivative assets and liabilities for
counterparties where we have a legal right of offset. On January 1, 2001, we
adopted SFAS No. 133 and recorded a cumulative effect adjustment of $459
million, net of income taxes, in accumulated other comprehensive income (loss)
to recognize the fair value of all derivatives designated as hedging instruments
on that date. The majority of the initial cumulative-effect adjustment related
to cash flow hedges

                                        72
<PAGE>

on anticipated sales of natural gas. During the year ended December 31, 2001,
$456 million, net of income taxes, of this initial adjustment was reclassified
to earnings as a result of completed sales and purchases during that year. See
Note 13 for a further discussion of our price risk management activities.

     Our income statement treatment of changes in fair value and settlements of
derivatives depends on the nature of the derivative instrument. Derivatives used
in our hedging activities are reflected as either revenues or expenses in our
income statements based on the nature and timing of the hedged transaction.
Derivatives related to our power contract restructuring activities are reflected
as either revenues (for settlements and changes in the fair values of the power
sales contracts) or expenses (for settlements and changes in the fair values of
the fuel supply agreements). Prior to 2003, we also had derivative contracts
related to our historical trading activities. These activities are reported in
revenue on a net basis (revenues net of the expenses of the physically settled
purchases). This net presentation began on July 1, 2002 with our adoption of
EITF Issue No. 02-3, Issues Related to Accounting for Contracts Involving Energy
Trading and Risk Management Activities, and all periods reflect this
presentation. Prior to its adoption, we reflected these activities on a gross
basis (physically settled revenues separate from physically settled expenses).
Upon its adoption, revenues and costs for the year ended December 31, 2001 were
revised as follows (in millions):

<Table>
<S>                                                           <C>
Gross operating revenues....................................     $ 5,006
Costs reclassified..........................................      (1,042)
                                                                 -------
  Net operating revenues reported in the income statement...     $ 3,964
                                                                 =======
</Table>

     In our cash flow statement, cash inflows and outflows associated with the
settlement of our derivative instruments are recognized in operating cash flows,
and any receivables and payables resulting from these settlements are reported
as trade receivables and payables in our balance sheet.

     During 2002, we also adopted Derivatives Implementation Group (DIG) Issue
No. C-16, Scope Exceptions: Applying the Normal Purchases and Sales Exception to
Contracts that Combine a Forward Contract and Purchased Option Contract. DIG
Issue No. C-16 requires that if a fixed-price fuel supply contract allows the
buyer to purchase, at their option, additional quantities at a fixed price, the
contract is a derivative that must be recorded at its fair value. One of our
unconsolidated affiliates, the Midland Cogeneration Venture Limited Partnership,
recognized a gain on one fuel supply contract upon adoption of these new rules,
and we recorded our proportionate share of this gain of $14 million, net of
income taxes, as a cumulative effect of an accounting change in our income
statement.

  Income Taxes

     We report current income taxes based on our taxable income and we provide
for deferred income taxes to reflect estimated future tax payments or receipts.
Deferred taxes represent the tax impacts of differences between the financial
statement and tax bases of assets and liabilities and carryovers at each year
end. We account for tax credits under the flow-through method, which reduces the
provision for income taxes in the year the tax credits first become available.
We reduce deferred tax assets by a valuation allowance when, based on our
estimates, it is more likely than not that a portion of those assets will not be
realized in a future period. The estimates utilized in recognition of deferred
tax assets are subject to revision, either up or down, in future periods based
on new facts or circumstances.

     El Paso maintains a tax accrual policy to record both regular and
alternative minimum tax for companies included in its consolidated federal and
state income tax returns. The policy provides, among other things, that (i) each
company in a taxable income position will accrue a current expense equivalent to
its federal and state income taxes, and (ii) each company in a tax loss position
will accrue a benefit to the extent its deductions, including general business
credits, can be utilized in the consolidated returns. El Paso pays all
consolidated U.S. federal and state income taxes directly to the appropriate
taxing jurisdictions and, under a separate tax billing agreement, El Paso may
bill or refund its subsidiaries for their portion of these income tax payments.

                                        73
<PAGE>

  Foreign Currency Transactions and Translation

     We record all currency transaction gains and losses in income. These gains
or losses are classified in our income statement based upon the nature of the
transaction that gives rise to the currency gain or loss. For sales and
purchases of commodities or goods, these gains or losses are included in
operating revenue or expense. These gains and losses were insignificant in 2003,
2002 and 2001. For gains and losses arising through equity investees, we record
these gains or losses as equity earnings. For gains or losses on foreign
denominated debt, we include these gains or losses as a component in other
expense. The net foreign currency loss recorded in other expense was
insignificant in 2003, 2002 and 2001. The U.S. dollar is the functional currency
for the majority of our foreign operations. For foreign operations whose
functional currency is deemed to be other than the U.S. dollar, assets and
liabilities are translated at year-end exchange rates and included as a separate
component of accumulated other comprehensive income (loss) in stockholders'
equity. The cumulative currency translation gain (loss) recorded in accumulated
other comprehensive income (loss) was $63 million and $(49) million at December
31, 2003 and 2002. Revenues and expenses are translated at average exchange
rates prevailing during the year.

  Accounting for Asset Retirement Obligations

     On January 1, 2003, we adopted SFAS No. 143, which requires that we record
a liability for retirement and removal costs of long-lived assets used in our
business. This liability is recorded at its estimated fair value, with a
corresponding increase to property, plant and equipment. This increase in
property, plant and equipment is then depreciated over the remaining useful life
of the long-lived asset to which that liability relates. An ongoing expense is
also recognized for changes in the value of the liability as a result of the
passage of time, which we record in depreciation, depletion and amortization
expense in our income statement. In the first quarter of 2003, we recorded a
charge as a cumulative effect of accounting change of approximately $12 million,
net of income taxes, related to our adoption of SFAS No. 143. We also recorded
property, plant and equipment of $125 million and asset retirement obligations
of $143 million as of January 1, 2003. These amounts have been restated to
reflect the impact of our reserve revisions on the timing of the settlement of
our asset retirement obligations as described in Note 1. Our asset retirement
obligations are associated with our natural gas and oil wells and related
infrastructure in our Production segment and our natural gas storage wells in
our Pipelines segment. We have obligations to plug wells when production on
those wells is exhausted, and we abandon them. We currently forecast that these
obligations will be met at various times, generally over the next ten years,
based on the expected productive lives of the wells and the estimated timing of
plugging and abandoning those wells. The net asset retirement liability as of
January 1, 2003 and December 31, 2003, reported in other current and non-current
liabilities in our balance sheet, and the changes in the net liability for the
year ended December 31, 2003, were as follows (in millions):

<Table>
<S>                                                           <C>
Net asset retirement liability at January 1, 2003...........    $  143
Liabilities settled in 2003.................................       (33)
Accretion expense in 2003...................................        16
Liabilities incurred in 2003................................         7
Changes in estimate.........................................         8
                                                                ------
  Net asset retirement liability at December 31, 2003.......    $  141
                                                                ======
</Table>

     Our changes in estimate represent changes to the expected amount and timing
of payments to settle our asset retirement obligations. These changes primarily
result from obtaining new information about the timing of our obligations to
plug our natural gas and oil wells and the costs to do so. Had we adopted SFAS
No. 143 as of January 1, 2001, our aggregate current and non-current retirement
liabilities on that date would have been approximately $130 million and our
income from continuing operations and net income for the years ended December
31, 2002 and 2001, would have been lower by $8 million in each year.

                                        74
<PAGE>

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

     In May 2003, the Financial Accounting Standards Board (FASB) issued SFAS
No. 150, Accounting for Certain Financial Instruments with Characteristics of
both Liabilities and Equity. This statement provides guidance on the
classification of financial instruments as equity, as liabilities, or as both
liabilities and equity. In particular, the standard requires that we classify
all mandatorily redeemable securities as liabilities in the balance sheet. On
July 1, 2003, we adopted the provisions of SFAS No. 150, and reclassified $300
million of our Coastal Finance I preferred interests from preferred interests of
consolidated subsidiaries to long-term financing obligations in our balance
sheet. We also began classifying dividends accrued on these preferred interests
as interest and debt expense in our income statement. For the year ended
December 31, 2003, total dividends were $26 million, of which $13 million were
recorded in interest expense and $13 million were recorded as distributions on
preferred interests in our income statement.

  New Accounting Pronouncements Issued But Not Yet Adopted

     As of December 31, 2003, there were several accounting standards and
interpretations that had been issued, but not yet adopted by us. Below is a
discussion of a significant standard that will impact us.

     Consolidation of Variable Interest Entities.  In January 2003, the FASB
issued Financial Interpretation (FIN) No. 46, Consolidation of Variable Interest
Entities, an Interpretation of ARB No. 51. This interpretation defines a
variable interest entity as a legal entity whose equity owners do not have
sufficient equity at risk and/or a controlling financial interest in the entity.
This standard requires a company to consolidate a variable interest entity if it
is allocated a majority of the entity's losses and/or returns, including fees
paid by the entity. In December 2003, the FASB issued FIN No. 46-R, which
amended FIN No. 46 to extend its effective date until the first quarter of 2004
for all types of entities except special purpose entities. In addition, FIN No.
46-R also limited the scope of FIN No. 46 to exclude certain joint ventures or
other entities that meet the characteristics of businesses.

     On January 1, 2004, we adopted this standard. Upon adoption, we
consolidated Blue Lake Gas Storage Company, an equity investment that owns the
Blue Lake natural gas storage facility. The impact of this consolidation was a
net increase to property, plant and equipment of $72 million, an increase to
other current and non-current assets of $6 million, an increase to third-party
debt of $14 million, an increase to other liabilities and equity of $15 million,
a decrease in our investment balance of $30 million, and a decrease to notes
receivable from affiliates of $19 million.

                                        75
<PAGE>

3. DIVESTITURES

     During 2002, 2003 and 2004, we completed or announced the sale of a number
of assets and investments in each of our business segments as follows:

<Table>
<Caption>
SEGMENT                       PROCEEDS(1)                 SIGNIFICANT ASSETS AND INVESTMENTS
-------                      -------------                ----------------------------------
                             (IN MILLIONS)
<S>                          <C>             <C>
Announced to date or
completed in 2004

Production                      $  410       - Natural gas and oil properties in Canada(3)
                                             - International exploration and production assets(3)

Merchant Energy                     92       - Utility Contract Funding (UCF)(2)
                                             - Mohawk River Funding IV(3)(4)
                                             - Equity interest in the Bastrop Company power investment(3)
                                             - Fulton power facility(3)
                                ------

Total continuing                   502

Discontinued                       905       - Aruba and Eagle Point refineries and other petroleum
                                               assets(3)
                                ------

Total                           $1,407
                                ======
</Table>

---------------

(1) Amounts on sales that have been announced or are under contract for sale are
    estimates, subject to customary regulatory approvals, final sale
    negotiations and other conditions.
(2) We sold our ownership interest in UCF in 2004 for $18 million in cash to an
    affiliate of Bear Stearns, which also assumed $815 million of UCF debt. We
    incurred a loss of approximately $90 million on this sale in 2004.
(3) These sales were completed in 2004.
(4) We sold our ownership interest in Mohawk River Funding IV for $3 million in
    cash to an affiliate of Bear Stearns, which also assumed $72 million of
    Mohawk River IV debt.

<Table>
<Caption>
SEGMENT                        PROCEEDS                   SIGNIFICANT ASSETS AND INVESTMENTS
-------                      -------------                ----------------------------------
                             (IN MILLIONS)
<S>                          <C>             <C>
Completed in 2003

Pipelines                       $   89       - Equity interest in Alliance Pipeline System and related
                                               assets
                                             - Horsham pipeline in Australia
                                             - Panhandle gathering system located in Texas

Production                         193       - Natural gas and oil properties located in western Canada,
                                               New Mexico and the Gulf of Mexico
                                             - Drilling rigs

Field Services                      94       - Gathering systems located in Wyoming
                                             - Midstream assets in the Mid-Continent region

Merchant Energy                     11       - Power contracts

Corporate and Other                 17       - Aircraft
                                ------

Total continuing(1)                404

Discontinued(2)                    747       - Corpus Christi refinery, Florida petroleum terminals and
                                             other coal and petroleum assets
                                ------

Total                           $1,151
                                ======
</Table>

---------------

(1) Includes $20 million of costs incurred in preparing assets for disposal,
    returns of invested capital and cash transferred with the assets sold.
(2) Includes $84 million of proceeds related to the sale of our asphalt
    facilities, which includes $39 million of cash, $27 million of accounts and
    notes receivable, and the release of $18 million of previously outstanding
    liabilities. In December 2003, we recorded a valuation allowance of $17
    million on these receivables, reducing them to their net realizable value.
    We continue to evaluate the financial condition of the purchaser in order to
    determine whether an additional valuation allowance on the receivables is
    necessary.

                                        76
<PAGE>

<Table>
<Caption>
SEGMENT                        PROCEEDS                   SIGNIFICANT ASSETS AND INVESTMENTS
-------                      -------------                ----------------------------------
                             (IN MILLIONS)
<S>                          <C>             <C>
Completed in 2002

Pipelines                       $  303       - Natural gas and oil properties located in Texas, Kansas
                                               and Oklahoma and their related contracts
                                             - 12.3 percent equity interest in Alliance Pipeline and
                                               related assets
                                             - Typhoon natural gas pipeline

Production                       1,297       - Natural gas and oil properties located in Texas, Colorado,
                                               Utah and western Canada

Field Services                     120       - Dragon Trail gas processing plant
                                             - Gathering facilities located in Utah
                                ------

Total continuing(1)              1,720

Discontinued                       128       - Coal reserves and properties and petroleum assets
                                ------

Total                           $1,848
                                ======
</Table>

---------------

(1) Includes $35 million of costs incurred in preparing assets for disposal,
    returns of invested capital and cash transferred with assets sold.

     During the years ended December 31, 2003, 2002 and 2001, our asset
impairments and net realized (gains) losses on long-lived assets were $97
million, $(7) million and $69 million and our impairments and net realized
(gains) losses on sales of investments were $128 million, $47 million and $(10)
million. These gains, losses and asset impairments are discussed in Notes 5, 10
and 22.

     For the year ended December 31, 2001, we sold our Gulfstream pipeline
project, our 50 percent interest in the Stingray and U-T Offshore pipeline
systems, and our investments in the Empire State and Iroquois pipeline systems.
Net proceeds from these sales were approximately $184 million, and we recognized
extraordinary net gains of approximately $11 million, net of income taxes of
approximately $5 million. These gains were treated as extraordinary since they
resulted from a Federal Trade Commission (FTC) order in connection with our
merger in 2001 with El Paso.

     Under SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived
Assets, we classify assets being disposed of that have received appropriate
approvals by our management and/or El Paso's Board of Directors as held for sale
or, if appropriate, discontinued operations. As of December 31, 2003 and 2002,
we had $7 million and $31 million of assets held for sale reflected in other
current assets on our balance sheet. Our assets held for sale as of December 31,
2003 related to domestic power assets in our Merchant Energy segment that were
approved by El Paso's Board of Directors for sale in 2003. Our assets held for
sale at December 31, 2002 related to gathering assets in our Field Services
segment which were sold during 2003.

     We continue to evaluate assets we may sell or otherwise divest of in the
future. As specific assets are identified for divestiture, we will be required
to record them at the lower of fair value, less selling costs, or historical
cost. This will require us to assess them for possible impairment. These
impairment charges, if any, will generally be based on their estimated fair
value as determined by market data obtained through the divestiture process or
by assessing the probability-weighted cash flows of the asset. For a discussion
of impairment charges incurred on our long-lived assets, see Note 5; for
impairments on discontinued operations, see Note 10; and for impairments on our
investments in unconsolidated affiliates, see Note 22.

                                        77
<PAGE>

4. MERGER-RELATED COSTS

     We did not incur any merger-related costs during 2003 and 2002. During
2001, we incurred merger-related costs in connection with our merger with El
Paso as follows:

<Table>
<Caption>
                                                                       FIELD     MERCHANT   CORPORATE
                                             PIPELINES   PRODUCTION   SERVICES    ENERGY    AND OTHER   TOTAL
                                             ---------   ----------   --------   --------   ---------   -----
                                                                      (IN MILLIONS)
<S>                                          <C>         <C>          <C>        <C>        <C>         <C>
Employee severance, retention and
  transition costs.........................    $ 76         $ 7         $ 2        $ 2        $480      $567
Business and operational integration
  costs....................................      86          15          --         --          22       123
Other......................................      30          23          11         15          18        97
                                               ----         ---         ---        ---        ----      ----
                                               $192         $45         $13        $17        $520      $787
                                               ====         ===         ===        ===        ====      ====
</Table>

     Employee severance, retention and transition costs include direct payments
to, and benefit costs for, severed employees and early retirees that occurred as
a result of our merger-related workforce reduction and consolidation. Following
our merger with El Paso, we completed an employee restructuring across all of
our operating segments, resulting in the reduction of 3,200 full-time positions
through a combination of early retirements and terminations.

     As a result of these actions, employee severance, retention, and transition
costs for 2001 were approximately $567 million which included $214 million of
pension and postretirement benefits which will be paid over the applicable
benefit periods of the terminated and retired employees and a charge of $278
million resulting from the issuance of approximately 4 million shares of El Paso
common stock on the date of our merger in exchange for the fair value of our
employees' and directors' stock options and restricted stock. A total of 339
employees and 11 directors received these shares. All other costs were expensed
and paid as incurred.

     Business and operational integration costs include charges to consolidate
facilities and operations of our business segments. Total charges in 2001 were
$123 million, which primarily included: (i) $15 million of incremental fees
under software and seismic license agreements which were recorded in our
Production segment, (ii) $108 million of estimated lease-related costs to
relocate our pipeline operations from Detroit, Michigan to Houston, Texas. In
addition, asset impairment charges of $13 million were incurred related to the
closure of this facility. The lease-related costs were accrued at the time we
completed our relocations and closed these offices and will be paid over the
term of the applicable non-cancelable lease agreements. All other costs were
expensed and paid as incurred.

     Other costs were $97 million, which include payments made in satisfaction
of obligations arising from the FTC approval of our merger with El Paso and
other miscellaneous charges. These items were expensed in the period in which
they were incurred.

                                        78
<PAGE>

5. LOSS (GAIN) ON LONG-LIVED ASSETS

     Loss (gain) on long-lived assets from continuing operations consists of
realized gains and losses on sales of long-lived assets and impairments of
long-lived assets including goodwill and other intangibles. During each of the
three years ended December 31, our loss on long-lived assets were as follows:

<Table>
<Caption>
                                                                     2002         2001
                                                           2003   (RESTATED)   (RESTATED)
                                                           ----   ----------   ----------
                                                                   (IN MILLIONS)
<S>                                                        <C>    <C>          <C>
Net realized (gain) loss.................................  $(35)     $(43)        $  4
                                                           ----      ----         ----
Asset impairments
  Merchant Energy
     Power assets........................................    28        18           --
     Other...............................................    --        --           21
  Production
     Canadian assets.....................................    14         4           --
     Australian and Indonesian assets....................    --        --           16
     Goodwill impairment.................................    75        --           --
     Other...............................................    10        --           --
  Pipelines..............................................    --        --           22
  Field Services.........................................     4        14           --
  Corporate..............................................     1        --            6
                                                           ----      ----         ----
     Total asset impairments.............................   132        36           65
                                                           ----      ----         ----
  Loss (gain) on long-lived assets.......................  $ 97      $ (7)        $ 69
                                                           ====      ====         ====
</Table>

  Net Realized (Gain) Loss

     Our 2003 net realized gain was primarily related to a $19 million gain on
the sales of our Mid-Continent midstream assets in our Field Services segment, a
$6 million gain on the sale of the Table Rock sulfur extraction facility in our
Pipelines segment, a $5 million gain on the sales of non-full cost pool assets
in our Production segment and $5 million of gains on the sales of other assets.
Our 2002 net gain was primarily related to $35 million of net gains on the sales
of our Natural Buttes and Ouray gathering systems and our Dragon Trail gas
processing plant in our Field Services segment and $10 million of other
miscellaneous asset sales in our Pipelines segment. See Note 3 for a further
discussion of these divestitures.

  Asset Impairments

     Our impairment charges for the years ended December 31, 2003, 2002 and 2001
were recorded primarily based on our intent to dispose of, or reduce our
involvement in a number of assets, as part of liquidity enhancement efforts. Our
Production charges include the write-down of goodwill in 2003 that occurred
based on our decision to reduce our involvement in our Canadian production
operations. Our Merchant Energy charges were primarily a result of our planned
sale of our power assets.

     For additional asset impairments on our discontinued operations and
investments in unconsolidated affiliates, see Notes 10 and 22. For additional
discussion on goodwill and other intangibles, see Note 2.

                                        79
<PAGE>

6. ACCOUNTING CHANGES

  Changes in Accounting Principle

     During the years ended December 31, 2003 and 2002, we recorded the
following cumulative effect of accounting changes due to the adoption of new
accounting pronouncements (in millions):

<Table>
<Caption>
                                                           BEFORE-TAX   AFTER-TAX
                                                           ----------   ---------
<S>                                                        <C>          <C>
2003
  SFAS No. 143 (restated -- See Note 1)..................     $(18)       $(12)
                                                              ====        ====
2002
  DIG Issue No. C-16.....................................     $ 23        $ 14
                                                              ====        ====
</Table>

     For a discussion of each of the accounting principles we adopted during
2003 and 2002, see Note 2.

  Changes in Accounting Estimate

     During 2001, we incurred approximately $316 million in costs related to
changes in accounting estimates, which consist of $232 million in additional
environmental remediation liabilities, $47 million in additional accrued legal
obligations and a $37 million charge to reduce the value of our spare parts
inventories to reflect changes in the usability of these parts in our
operations. Of the overall pre-tax amount, approximately $182 million of these
costs were included in our continuing operation and maintenance costs and $134
million were related to our discontinued petroleum markets and coal businesses
included discontinued operations. Our changes in estimates reduced our overall
net income by approximately $241 million, of which $150 million was related to
continuing operations and $91 million was related to discontinued operations.

     The change in our estimated environmental remediation liabilities was due
to a number of events including the sale, closure or lease of a number of the
businesses and assets in our discontinued petroleum markets operations, and
conforming our methods of environmental identification, assessment and
remediation strategies and processes to El Paso's historical practices following
our merger with El Paso.

7. CEILING TEST CHARGES

     See Note 1 for a discussion of the restatement of our historical reserves
and Note 24 for a discussion of our natural gas and oil reserves.

     During the years ended December 31, 2003, 2002 and 2001, we incurred
ceiling test charges in the following full cost pools:

<Table>
<Caption>
                                                                     2002         2001
                                                           2003   (RESTATED)   (RESTATED)
                                                           ----   ----------   ----------
                                                                   (IN MILLIONS)
<S>                                                        <C>    <C>          <C>
U.S. ....................................................  $ 34      $417         $257
Canada...................................................    61        91          225
Brazil...................................................     5         3           50
Indonesia................................................    --         1            5
Australia and other international countries..............     9         9           --
                                                           ----      ----         ----
  Total..................................................  $109      $521         $537
                                                           ====      ====         ====
</Table>

     We use financial instruments to hedge against the volatility of natural gas
and oil prices. The impact of qualifying cash flow hedges was considered in
determining our ceiling test charges, and will be factored into future ceiling
test calculations. The charges for our international cost pools would not have
materially changed had the impact of our hedges not been included in calculating
our ceiling test charges since we do not significantly hedge our international
production activities. Had the impact of qualifying cash flow hedges been
excluded from our U.S. full cost pool calculations, we would have incurred no
ceiling test charges in 2003, and

                                        80
<PAGE>

would have incurred charges of $576 million in 2002 and $1,424 million in 2001
compared with the charges we actually recorded.

8. OTHER INCOME AND OTHER EXPENSES

     The following are the components of other income and other expenses from
continuing operations for each of the three years ended December 31:

<Table>
<Caption>
                                                              2003   2002   2001
                                                              ----   ----   ----
                                                                (IN MILLIONS)
<S>                                                           <C>    <C>    <C>
Other Income
  Interest income...........................................  $ 17   $13    $23
  Re-application of SFAS No. 71 (CIG and WIC)...............    18    --     --
  Development, management and administrative services fees
     on power projects......................................    11    11     12
  Favorable resolution of non-operating contingent
     obligations............................................     8    31      4
  Rental income.............................................    --    --     22
  Other.....................................................    12    15     20
                                                              ----   ---    ---
          Total.............................................  $ 66   $70    $81
                                                              ====   ===    ===
Other Expenses
  Minority interest in consolidated subsidiaries............  $(12)  $52    $--
  Other.....................................................     7    18     18
                                                              ----   ---    ---
          Total.............................................  $ (5)  $70    $18
                                                              ====   ===    ===
</Table>

9. INCOME TAXES

     Our pretax income (loss) from continuing operations is composed of the
following for each of the three years ended December 31:

<Table>
<Caption>
                                                                     2002         2001
                                                          2003    (RESTATED)   (RESTATED)
                                                          -----   ----------   ----------
                                                                   (IN MILLIONS)
<S>                                                       <C>     <C>          <C>
U.S. ...................................................  $ 240      $363        $(312)
Foreign.................................................   (122)       62         (268)
                                                          -----      ----        -----
                                                          $ 118      $425        $(580)
                                                          =====      ====        =====
</Table>

                                        81
<PAGE>

     The following table reflects the components of income tax expense (benefit)
included in income (loss) from continuing operations for each of the three years
ended December 31:

<Table>
<Caption>
                                                                     2002         2001
                                                         2003     (RESTATED)   (RESTATED)
                                                         -----    ----------   ----------
                                                                  (IN MILLIONS)
<S>                                                      <C>      <C>          <C>
Current
  Federal..............................................  $  68       $(35)       $  47
  State................................................     14          2           (1)
  Foreign..............................................     --          5            4
                                                         -----       ----        -----
                                                            82        (28)          50
                                                         -----       ----        -----
Deferred
  Federal..............................................    (93)       141          (21)
  State................................................    (12)        33          (11)
  Foreign..............................................    (34)       (37)        (105)
                                                         -----       ----        -----
                                                          (139)       137         (137)
                                                         -----       ----        -----
          Total income tax expense (benefit)...........  $ (57)      $109        $ (87)
                                                         =====       ====        =====
</Table>

     Our income tax expense (benefit), included in income (loss) from continuing
operations differs from the amount computed by applying the statutory federal
income tax rate of 35 percent for the following reasons for each of the three
years ended December 31:

<Table>
<Caption>
                                                                    2002          2001
                                                        2003     (RESTATED)    (RESTATED)
                                                        -----    ----------    ----------
                                                           (IN MILLIONS EXCEPT RATES)
<S>                                                     <C>      <C>           <C>
Income tax expense (benefit) at the statutory federal
  rate of 35%.........................................  $  41       $149         $(203)
Increase (decrease)
  State income tax, net of federal income tax
     effect...........................................      1         23            (8)
  Foreign (income) loss taxed at different tax
     rates............................................     34        (66)          (20)
  Depreciation, depletion and amortization............     --         --            20
  Non-taxable stock dividends.........................     (5)        (5)           (4)
  Non-deductible portion of merger-related costs and
     other tax adjustments to provide for revised
     estimated liabilities............................     --         --           106
  Abandonments and sales of foreign investments.......   (105)        --            --
  Valuation allowances................................    (21)        (3)           19
  Other...............................................     (2)        11             3
                                                        -----       ----         -----
Income tax expense (benefit)..........................  $ (57)      $109         $ (87)
                                                        =====       ====         =====
Effective tax rate....................................    (48)%       26%           15%
                                                        =====       ====         =====
</Table>

                                        82
<PAGE>

     The following are the components of our net deferred tax liability related
to continuing operations as of December 31:

<Table>
<Caption>
                                                                           2002
                                                                2003    (RESTATED)
                                                               ------   ----------
                                                                  (IN MILLIONS)
<S>                                                            <C>      <C>
Deferred tax liabilities
  Property, plant and equipment.............................   $  883     $1,277
  Investments in unconsolidated affiliates..................      302        216
  Regulatory and other assets...............................       80        108
                                                               ------     ------
          Total deferred tax liability......................    1,265      1,601
                                                               ------     ------
Deferred tax assets
  Net operating loss and tax credit carryovers:
     U.S. federal...........................................      267        217
     State..................................................       37          9
  Environmental liability...................................       59         57
  Price risk management activities..........................       55         52
  Allocated merger costs....................................      107        112
  Other.....................................................       97         97
  Valuation allowance.......................................       (1)       (27)
                                                               ------     ------
          Total deferred tax asset..........................      621        517
                                                               ------     ------
Net deferred tax liability..................................   $  644     $1,084
                                                               ======     ======
</Table>

     Included in our deferred tax assets as of December 31, 2003 are amounts
related to abandonments and sales of certain of our foreign investments that
have occurred in 2003 or 2004.

     At December 31, 2003, the portion of the cumulative undistributed earnings
of our foreign subsidiaries and foreign corporate joint ventures on which we
have not recorded U.S. income taxes was approximately $370 million. Since these
earnings have been or are intended to be indefinitely reinvested in foreign
operations, no provision has been made for any U.S. taxes or foreign withholding
taxes that may be applicable upon actual or deemed repatriation. If a
distribution of these earnings were to be made, we might be subject to both
foreign withholding taxes and U.S. income taxes, net of any allowable foreign
tax credits or deductions. However, an estimate of these taxes is not
practicable. For these same reasons, we have not recorded a provision for U.S.
income taxes on the foreign currency translation adjustment recorded in other
comprehensive income (loss).

     Under El Paso's tax accrual policy, we are allocated the tax effects
associated with our employee's nonqualified dispositions of employee stock
purchase plan stock, the exercise of non-qualified stock options and the vesting
of restricted stock, as well as restricted stock dividends. This allocation
increased taxes payable by $4 million in 2003 and reduced taxes payable by $2
million in 2002 and $5 million in 2001. These tax effects are included in
additional paid-in capital in our balance sheets.

     As of December 31, 2003, we had alternative minimum tax credits of $217
million that carryover indefinitely. The table below presents the details of our
federal and state net operating loss carryover periods as of December 31, 2003.

<Table>
<Caption>
                                                                   CARRYOVER PERIOD
                                                   ------------------------------------------------
                                                   2004   2005-2010   2011-2015   2016-2023   TOTAL
                                                   ----   ---------   ---------   ---------   -----
<S>                                                <C>    <C>         <C>         <C>         <C>
U.S. federal net operating loss..................  $ --     $ --        $ --        $143      $143
State net operating loss.........................    66      235           1         144       446
</Table>

     Usage of our U.S. federal carryovers is subject to the limitations provided
under Sections 382 and 383 of the Internal Revenue Code as well as the separate
return limitation year rules of IRS regulations.

                                        83
<PAGE>

     We record a valuation allowance to reflect the estimated amount of deferred
tax assets which we may not realize due to uncertain availability of future
taxable income or the expiration of net operating loss and tax credit
carryovers. As of December 31, 2003, we maintained a valuation allowance of $1
million related to foreign deferred tax assets for ceiling test charges. As of
December 31, 2002, we maintained valuation allowances of $22 million related to
foreign deferred tax assets for ceiling test charges and $5 million related to
state net operating loss carryovers. The change in our valuation allowances from
December 31, 2002 to December 31, 2003 is primarily related to foreign ceiling
test charges and revisions of future revenue estimates. On June 29, 2004, the
State of New Jersey enacted legislation that may limit the use of our New Jersey
net operating loss carryovers for tax years 2004 and 2005. This enacted
legislation may cause us to record an additional valuation allowance in either
2004 or 2005.

10. DISCONTINUED OPERATIONS

  Petroleum Markets Operations

     In June 2003, El Paso's Board of Directors authorized the sale of our
petroleum markets operations, including our Aruba refinery, our Unilube blending
operations, our domestic and international terminalling facilities and our
petrochemical and chemical plants. The Board's actions were in addition to
previous actions approving the sales of our Eagle Point refinery, our asphalt
business, our Florida terminal, tug and barge business and our lease crude
operations. Based on our intent to dispose of these operations, we were required
to adjust these assets to their estimated fair value. As a result, we recognized
pre-tax charges during 2003 totaling $1.5 billion related to impairments of our
petroleum markets assets, which included $1.1 billion related to our Aruba
refinery and $264 million related to the impairment of our Eagle Point refinery.
These impairments were based on a comparison of the carrying value of our
petroleum markets assets to their estimated fair value, less selling costs. In
the first quarter of 2004, we completed the sales of our Aruba and Eagle Point
refineries for $880 million and used a portion of the proceeds to repay $370
million of debt associated with these operations. The magnitude of these charges
was impacted by a number of factors, including the nature of the assets to be
sold, and our established time frame for completing the sales, among other
factors. We also recognized $90 million of realized gains primarily on the sale
of our Florida terminalling and transportation assets, asphalt facilities and
chemical facilities in 2003. During 2003 and 2004, we sold substantially all of
our petroleum markets assets.

  Coal Mining Operations

     In June 2002, El Paso's Board of Directors authorized the sale of our coal
mining operations. These operations, consisted of fifteen active underground and
two surface mines located in Kentucky, Virginia and West Virginia. Following
this approval, we compared the carrying value of the underlying assets to our
estimated sales proceeds, net of estimated selling costs, based on bids received
in the sales process. Because this carrying value was higher than our estimated
net sales proceeds, we recorded an impairment charge of $185 million during
2002.

     In December 2002, we sold substantially all of our reserves and properties
in West Virginia, Virginia and Kentucky to an affiliate of Natural Resources
Partners, L.P. for $57 million in cash. In January 2003, we sold our remaining
coal operations, which consisted of mining operations, businesses, properties
and reserves in Kentucky, West Virginia and Virginia for $59 million which
included $35 million in cash and $24 million in notes receivable. We did not
record a significant gain or loss on these sales in 2002 and 2003.

     Our petroleum markets operations and our coal mining operations are
classified as discontinued operations in our financial statements for all of the
historical periods presented. All of the assets and liabilities of the remaining
discontinued businesses are classified as current assets and liabilities as of

                                        84
<PAGE>

December 31, 2003. The summarized financial results and financial position data
of our discontinued operations were as follows:

<Table>
<Caption>
                                                           PETROLEUM    COAL
                                                            MARKETS    MINING    TOTAL
                                                           ---------   ------   -------
                                                                  (IN MILLIONS)
<S>                                                        <C>         <C>      <C>
Operating Results

YEAR ENDED DECEMBER 31, 2003
Revenues(1)..............................................   $ 5,697    $  27    $ 5,724
Costs and expenses(1)....................................    (5,837)     (13)    (5,850)
Loss on long-lived assets................................    (1,404)      (9)    (1,413)
Other income (expense)...................................        (4)       1         (3)
Interest and debt expense................................       (11)      --        (11)
                                                            -------    -----    -------
Income (loss) before income taxes........................    (1,559)       6     (1,553)
Income taxes.............................................      (261)       5       (256)
                                                            -------    -----    -------
Income (loss) from discontinued operations, net of income
  taxes..................................................   $(1,298)   $   1    $(1,297)
                                                            =======    =====    =======

YEAR ENDED DECEMBER 31, 2002
Revenues(1)..............................................   $ 4,814    $ 309    $ 5,123
Costs and expenses(1)....................................    (4,954)    (327)    (5,281)
Loss on long-lived assets................................       (97)    (184)      (281)
Other income.............................................        20        5         25
Interest and debt expense................................       (12)      --        (12)
                                                            -------    -----    -------
Loss before income taxes.................................      (229)    (197)      (426)
Income taxes.............................................        12      (73)       (61)
                                                            -------    -----    -------
Loss from discontinued operations, net of income taxes...   $  (241)   $(124)   $  (365)
                                                            =======    =====    =======

YEAR ENDED DECEMBER 31, 2001
Revenues(1)..............................................   $ 4,900    $ 277    $ 5,177
Costs and expenses(1)....................................    (5,016)    (286)    (5,302)
Loss on long-lived assets................................      (106)      --       (106)
Other income.............................................       111        2        113
Interest and debt expense................................       (27)      --        (27)
                                                            -------    -----    -------
Loss before income taxes.................................      (138)      (7)      (145)
Income taxes.............................................       (58)      (2)       (60)
                                                            -------    -----    -------
Loss from discontinued operations, net of income taxes...   $   (80)   $  (5)   $   (85)
                                                            =======    =====    =======
</Table>

---------------

(1) These amounts include intercompany activities between our discontinued
    petroleum markets operations and our continuing operating segments.

                                        85
<PAGE>

<Table>
<Caption>
                                                            PETROLEUM    COAL
                                                             MARKETS    MINING   TOTAL
                                                            ---------   ------   ------
                                                                   (IN MILLIONS)
<S>                                                         <C>         <C>      <C>
Financial Position Data

DECEMBER 31, 2003
Assets of discontinued operations
  Accounts and notes receivables..........................   $  262      $ --    $  262
  Inventory...............................................      385        --       385
  Other current assets....................................      131        --       131
  Property, plant and equipment, net......................      521        --       521
  Other non-current assets................................       70        --        70
                                                             ------      ----    ------
     Total assets of discontinued operations..............   $1,369      $ --    $1,369
                                                             ======      ====    ======
Liabilities of discontinued operations
  Accounts payable........................................   $  172      $ --    $  172
  Other current liabilities...............................       86        --        86
  Long-term debt..........................................      374        --       374
  Environmental remediation reserve.......................       24        --        24
  Other non-current liabilities...........................        2        --         2
                                                             ------      ----    ------
     Total liabilities of discontinued operations.........   $  658      $ --    $  658
                                                             ======      ====    ======

DECEMBER 31, 2002
Assets of discontinued operations
  Accounts and notes receivables..........................   $1,229      $ 29    $1,258
  Inventory...............................................      636        14       650
  Other current assets....................................       79         1        80
  Property, plant and equipment, net......................    1,950        46     1,996
  Other non-current assets................................       65        16        81
                                                             ------      ----    ------
     Total assets of discontinued operations..............   $3,959      $106    $4,065
                                                             ======      ====    ======
Liabilities of discontinued operations
  Accounts payable........................................   $1,153      $ 20    $1,173
  Other current liabilities...............................      180         5       185
  Environmental remediation reserve.......................       86        15       101
  Other non-current liabilities...........................        1        --         1
                                                             ------      ----    ------
     Total liabilities of discontinued operations.........   $1,420      $ 40    $1,460
                                                             ======      ====    ======
</Table>

11. FINANCIAL INSTRUMENTS

     The following table presents the carrying amounts and estimated fair values
of our financial instruments as of December 31:

<Table>
<Caption>
                                                                 2003                    2002
                                                         ---------------------   ---------------------
                                                         CARRYING                CARRYING
                                                          AMOUNT    FAIR VALUE    AMOUNT    FAIR VALUE
                                                         --------   ----------   --------   ----------
                                                                         (IN MILLIONS)
<S>                                                      <C>        <C>          <C>        <C>
     Long-term financing obligations, including current
       maturities......................................   $5,321      $5,233      $5,354      $4,637
     Company-obligated preferred securities of
       subsidiaries(1).................................       --          --         300         160
     Commodity-based price risk management
       derivatives.....................................      818         818         818         818
</Table>

---------------

(1) These were reclassified as long-term financing obligations upon our adoption
    of SFAS No. 150 in 2003.

                                        86
<PAGE>

     As of December 31, 2003 and 2002, the carrying amounts of cash and cash
equivalents, short-term borrowings, and trade receivables and payables represent
fair value because of the short-term nature of these instruments. The fair value
of long-term debt with variable interest rates approximates its carrying value
because of the market-based nature of the interest rate. We estimated the fair
value of debt with fixed interest rates based on quoted market prices for the
same or similar issues. See Note 12 for a discussion of our methodology of
determining the fair value of the derivative instruments used in our price risk
management activities.

     For the years ended December 31, 2003 and 2002, we had one customer that
comprised greater than five percent of our net credit exposure from our price
risk management activities. This customer, Public Service Electric and Gas
Company (PSEG), comprised $812 million and $896 million of the net exposure as
of December 31, 2003 and 2002. PSEG was rated as investment grade by Moody's
Investor Services and Standard & Poor's, and we have not required any collateral
from them as of December 31, 2003 and 2002. This concentration of counterparties
may impact our overall exposure to credit risk, either positively or negatively,
in that the counterparties may be similarly affected by changes in economic,
regulatory or other conditions. As a result of our sale of UCF in 2004, this
exposure was substantially reduced.

12. PRICE RISK MANAGEMENT ACTIVITIES

     In the table below, derivatives designated as hedges consist of instruments
used to hedge our natural gas and oil production as well as instruments to hedge
our interest rate risks on long-term debt. Derivatives from power contract
restructuring activities relate to power purchase and sale agreements that arose
from our activities in that business. The following table summarizes the
carrying value of the derivatives used in our price risk management activities
as of December 31:

<Table>
<Caption>
                                                              2003    2002
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
Net assets (liabilities)
  Derivatives designated as hedges..........................  $(124)  $(146)
  Derivatives from power contract restructuring
     activities.............................................    942     968
  Other commodity-based derivative contracts................     --      (4)
                                                              -----   -----
       Net assets from price risk management
        activities(1).......................................  $ 818   $ 818
                                                              =====   =====
</Table>

---------------
(1) Included in both current and non-current assets and liabilities on the
    balance sheet.

     Our derivative contracts are recorded in our financial statements at fair
value. The best indication of fair value is quoted market prices. However, when
quoted market prices are not available, we estimate the fair value of those
derivatives. Due to major industry participants exiting or reducing their
trading activities in 2002 and 2003, the availability of reliable commodity
pricing data from market-based sources that we used in estimating the fair value
of our derivatives was significantly limited for certain locations and for
longer time periods. Consequently, we now use an independent pricing source for
a substantial amount of our forward pricing data beyond the current two-year
period. For forward pricing data within two years, we use commodity prices from
market-based sources such as the New York Mercantile Exchange. For periods
beyond two years, we use a combination of commodity prices from market-based
sources and other forecasted settlement prices from an independent pricing
source to develop price curves, which we then use to estimate the value of
settlements in future periods based on the contractual settlement quantities and
dates. Finally, we discount these estimated settlement values using a LIBOR
curve, except as described below for our restructured power contracts.

     We record valuation adjustments to reflect uncertainties associated with
the estimates we use in determining fair value. Common valuation adjustments
include those for market liquidity and those for the credit-worthiness of our
contractual counterparties. To the extent possible, we use market-based data
together with quantitative methods to measure the risks for which we record
valuation adjustments and to determine the level of these valuation adjustments.

                                        87
<PAGE>

     The above valuation techniques are used for valuing derivative contracts
that are used to hedge our natural gas production. We have adjusted this method
to determine the fair value of our restructured power contracts. Our
restructured power derivatives use the same methodology discussed above for
determining the forward settlement prices but are discounted using a risk free
interest rate, adjusted for the individual credit spread for each counterparty
to the contract. Additionally, no liquidity valuation adjustment is provided on
these derivative contracts since they are intended to be held through maturity.

  Derivatives Designated as Hedges

     We engage in hedges of cash flow exposure primarily related to our natural
gas and oil production activities. Hedges of cash flow exposure are designed to
hedge forecasted sales transactions or the variability of cash flows to be
received or paid related to a recognized asset or liability. Changes in
derivative fair values that are designated as cash flow hedges are deferred in
accumulated other comprehensive income to the extent they are effective and are
not included in income until the hedged transactions occur and are recognized in
earnings. The ineffective portion of the hedge's change in value is recognized
immediately in earnings as a component of operating revenues in our income
statement.

     We formally document all relationships between hedging instruments and
hedged items, as well as our risk management objectives, strategies for
undertaking various hedge transactions and our methods for assessing and testing
correlation and hedge ineffectiveness. All hedging instruments are linked to the
hedged asset, liability, firm commitment or forecasted transaction. We also
assess whether these derivatives are highly effective in offsetting changes in
cash flows or fair values of the hedged items. We discontinue hedge accounting
prospectively if we determine that a derivative is no longer highly effective as
a hedge or if we decide to discontinue the hedging relationship.

     A summary of the impacts of our cash flow hedges included in accumulated
other comprehensive income (loss), net of income taxes, as of December 31, 2003
and 2002 follows:

<Table>
<Caption>
                                                     ACCUMULATED
                                                        OTHER
                                                    COMPREHENSIVE       ESTIMATED
                                                    INCOME (LOSS)     INCOME (LOSS)         FINAL
                                                    -------------    RECLASSIFICATION    TERMINATION
                                                    2003     2002       IN 2004(1)          DATE
                                                    ----     ----    ----------------    -----------
<S>                                                 <C>      <C>     <C>                 <C>
Held by consolidated entities.....................  $(49)    $(39)         $ (1)            2005
Held by unconsolidated affiliates.................    13       16             5             2005
Undesignated(2)...................................   (25)     (55)          (25)            2004
                                                    ----     ----          ----
Total cash flow hedges............................  $(61)    $(78)         $(21)
                                                    ====     ====          ====
</Table>

---------------

(1) Reclassifications occur upon the physical delivery of the hedge commodity
    and the corresponding expiration of the hedge.
(2) In May 2002, we announced the plan to reduce the volumes of natural gas
    hedges for our Production segment, and, as a result, we removed the hedging
    designation on these derivatives.

     For the years ended December 31, 2003, 2002 and 2001, we recognized net
losses of $1 million, $3 million and $1 million, net of income taxes, in our
income from continuing operations related to the ineffective portion of all cash
flow hedges.

  Power Contract Restructuring Activities

     During 2001 and 2002, we conducted power contract restructuring activities
that involved amending or terminating power purchase contracts at existing power
facilities. In a restructuring transaction, we would eliminate the requirement
that the plant provide power from its own generation to the customer of the
contract (usually a regulated utility) and replace that requirement with a new
contract that gave us the ability to provide power to the customer from the
wholesale power market. In conjunction with these power restructuring
activities, we generally entered into additional market-based contracts with El
Paso Merchant Energy, our affiliate, to provide the power from the wholesale
power market, which effectively "locked in" our

                                        88
<PAGE>

margin on the restructured transaction as the difference between the contracted
rate in the restructured sales contract and the wholesale market rates on the
power purchase contract at the time.

     Prior to a restructuring, the power plant and its related power purchase
contract were accounted for at their historical cost, which was either the cost
of construction or, if acquired, the acquisition cost. Revenues and expenses
prior to the restructuring were, in most cases, accounted for on an accrual
basis as power was generated and sold from the plant.

     Following a restructuring, the accounting treatment for the power purchase
agreement changed since the restructured contract met the definition of a
derivative. In addition, since the power plant no longer had the exclusive
obligation to provide power under the original, dedicated power purchase
contract, it operated as a peaking merchant facility, generating power only when
it was economical to do so. Because of this significant change in its use, the
plant's carrying value was typically written down to its estimated fair value.
These changes also often required us to terminate or amend any related fuel
supply and/or steam agreements, and enter into other third-party and
intercompany contracts such as transportation agreements, associated with
operating the merchant facility. Finally, in many cases power contract
restructuring activities also involved contract terminations that resulted in
cash payments by the customer to cancel the underlying dedicated power contract.

     In 2002, we completed a power contract restructuring on our consolidated
Eagle Point power facility and applied the accounting described above to that
transaction. We also employed the principles of our power contract restructuring
business in reaching a settlement of a dispute under our Nejapa power contract
which included a cash payment to us. We recorded these payments as operating
revenues. As of and for the year ended December 31, 2002, our consolidated power
restructuring activities had the following effects on our consolidated financial
statements (in millions):

<Table>
<Caption>
                                                                  PROPERTY,
                               ASSETS FROM   LIABILITIES FROM     PLANT AND                              INCREASE
                               PRICE RISK       PRICE RISK      EQUIPMENT AND                           (DECREASE)
                               MANAGEMENT       MANAGEMENT       INTANGIBLE     OPERATING   OPERATING   IN MINORITY
                               ACTIVITIES       ACTIVITIES         ASSETS       REVENUES    EXPENSES    INTEREST(1)
                               -----------   ----------------   -------------   ---------   ---------   -----------
<S>                            <C>           <C>                <C>             <C>         <C>         <C>
Initial gain on restructured
  contracts..................     $978             $ 80                          $  988                    $ 172
Write-down of power plants
  and intangibles and other
  fees.......................                                       $(328)                    $489          (109)
Change in value of
  restructured contracts
  during 2002................        8                                              (96)                     (20)
Change in value of
  third-party wholesale power
  supply contracts...........                       (62)                             62                       (3)
Purchase of power under power
  supply contracts...........                                                                   47           (11)
Sale of power under
  restructured contracts.....                                                       111                       28
                                  ----             ----             -----        ------       ----         -----
Total........................     $986             $ 18             $(328)       $1,065       $536         $  57
                                  ====             ====             =====        ======       ====         =====
</Table>

---------------

(1) In our restructuring activities, third-party owners also held ownership
    interests in the plants and were allocated a portion of the income or loss.

     During 2003 no new power restructuring transactions were completed and, as
a result, our consolidated financial statements for the year ended December 31,
2003 only reflect the change in value of the above restructured contracts and
power supply contracts, and the related purchases and sales under these
contracts. As a result of our credit downgrade and economic changes in the power
market, we are no longer pursuing additional power contract restructuring
activities. In June 2004, we completed the sale of UCF (which is the
restructured Eagle Point power contract).

                                        89
<PAGE>

13. INVENTORY

     We have the following inventory as of December 31:

<Table>
<Caption>
                                                              2003     2002
                                                              -----    -----
                                                              (IN MILLIONS)
<S>                                                           <C>      <C>
       Materials and supplies and other.....................   $58      $61
                                                               ===      ===
</Table>

14. REGULATORY ASSETS AND LIABILITIES

     Our regulatory assets and liabilities are included in other current and
non-current assets and liabilities in our balance sheets. These balances are
presented in our balance sheets on a gross basis. During 2003, CIG and WIC met
the requirements to re-apply the provisions of SFAS No. 71. As a result of
applying this standard, we recorded $18 million in regulatory assets and a
pre-tax benefit of $18 million in our 2003 income statement. In addition, $2
million of other assets and $10 million of other liabilities were reclassified
as regulatory assets/ liabilities upon re-application of SFAS No. 71. Below are
the details of our regulatory assets and liabilities, which represent our
regulated interstate systems that apply the provisions of SFAS No. 71, as of
December 31:

<Table>
<Caption>
                                                                              REMAINING
                                                                              RECOVERY
DESCRIPTION                                                       2003         PERIOD
-----------                                                       ----        ---------
                                                              (IN MILLIONS)   (YEARS)
<S>                                                           <C>             <C>
Non-current regulatory assets
  Grossed-up deferred taxes on capitalized funds used during
     construction(1)........................................       $12          23-29
  Postretirement benefits...................................         6              7
  Under-collected federal income taxes(1)...................         2            N/A
                                                                   ---
     Total regulatory assets(2).............................       $20
                                                                   ===
Current regulatory liabilities
  Postretirement benefits(1)................................       $ 1            N/A
                                                                   ---
Non-current regulatory liabilities
  Excess deferred federal income taxes......................         4              7
  Over-collected fuel obligation............................         5            N/A
                                                                   ---
     Total non-current regulatory liabilities...............         9
                                                                   ---
     Total regulatory liabilities(2)........................       $10
                                                                   ===
</Table>

---------------

(1) These amounts are not included in our rate base on which we earn a current
    return.

(2) Amounts are included as other non-current assets and other current and
    non-current liabilities in our balance sheets.

15. PROPERTY, PLANT AND EQUIPMENT

     At December 31, 2003 and 2002, we had approximately $373 million and $666
million of construction work-in-progress included in our property, plant and
equipment.

     As of December 31, 2003 and 2002, ANR has excess purchase costs associated
with its acquisition. Total excess costs on this pipeline were approximately $2
billion. These excess costs are being amortized over the life of the related
pipeline assets, and our amortization expense during each of the three years
ended December 31, 2003, 2002 and 2001 was approximately $34 million. The
adoption of SFAS No. 142 did not impact these amounts since they were included
as part of our property, plant and equipment, rather than as goodwill. We do not
earn a return on these excess purchase costs from our rate payers.

                                        90
<PAGE>

16. DEBT, OTHER FINANCING OBLIGATIONS AND OTHER CREDIT FACILITIES

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

<Table>
<Caption>
                                                               2003     2002
                                                              ------   ------
                                                               (IN MILLIONS)
<S>                                                           <C>      <C>
Long-term debt
  El Paso CGP
     Senior notes, 6.2% through 8.125%, due 2004 through
      2010..................................................  $1,305   $1,305
     Floating rate senior notes, due 2003...................      --      200
     Senior debentures, 6.375% through 10.75%, due 2004
      through 2037..........................................   1,395    1,497
     Valero lease financing loan due 2004(1)................      --      240
  Power
     Non-recourse senior notes, 7.75% and 7.944%, due 2008
      and 2016..............................................     904      915
     Recourse notes 8.5%, due 2005..........................      81      126
  El Paso Production Company
     Floating rate notes, due 2005 and 2006.................     200      200
  ANR Pipeline
     Debentures and senior notes, 7.0% through 9.625%, due
      2010 through 2025.....................................     800      500
     Notes, 13.75% due 2010.................................      13       13
  Colorado Interstate Gas
     Debentures, 6.85% and 10.0%, due 2005 and 2037.........     280      280
  Other.....................................................      51       84
                                                              ------   ------
          Subtotal..........................................   5,029    5,360
                                                              ------   ------
Other financing obligations
  Coastal Finance I.........................................     300       --
                                                              ------   ------
                                                               5,329    5,360
  Less:
     Unamortized discount on long-term debt.................       8        6
     Current maturities of long term debt and other
      financing obligations.................................     310      369
                                                              ------   ------
          Total long-term financing obligations, less
            current maturities..............................  $5,011   $4,985
                                                              ======   ======
</Table>

---------------

(1) The Valero lease financing loan, a general corporate obligator, was
    collateralized by the lease payments from Valero under their lease of our
    Corpus Christi refinery. This loan was repaid in February 2003.

                                        91
<PAGE>

     During 2003 and to date in 2004, we had the following changes in our debt
financing obligations:

<Table>
<Caption>
                                                                                                       NET
                                                                           INTEREST                PROCEEDS(1)/   DUE
         DATE                    COMPANY                   TYPE              RATE      PRINCIPAL   RETIREMENTS    DATE
         ----                    -------                   ----            --------    ---------   ------------   ----
                                                                                            (IN MILLIONS)
<S>                     <C>                         <C>                  <C>           <C>         <C>            <C>
Issuance
  March                 ANR                         Senior notes            8.875%      $  300        $  288      2010
                                                                                        ======        ======

Retirements
  January-December      El Paso CGP                 Long-term debt         Various      $  103        $  103
  February              El Paso CGP                 Long-term debt          4.49%          240           240
  July                  El Paso CGP                 Note                   Floating        200           200
                                                                             rate
  August                El Paso CGP                 Senior debentures       9.75%          102           102
                                                                                        ------        ------
                         Retirements through December 31, 2003.......................      645           645
                                                                                        ------        ------

  March 2004            El Paso Production Company  Note                 LIBOR + 3.5%      200           200
  May 2004              El Paso CGP                 Note                    6.20%          190           190
  January-September
    2004                El Paso CGP                 Long-term debt         Various          77            77
                                                                                        ------        ------
                                                                                        $1,112        $1,112
                                                                                        ======        ======
Other Changes in Debt
  July 2003             Coastal Finance I(2)        Preferred               8.375%      $  300        $  300      2038
                                                      securities
                                                                                        ------        ------
                         Other Changes through December 31, 2003.....................      300           300
                                                                                        ------        ------

  January 2004          Blue Lake Gas Storage       Term loan            LIBOR + 1.2%       14            14      2006
  March 2004            Mohawk River Funding IV(3)  Note                    7.75%          (72)          (72)     2008
  June 2004             Utility Contract            Non-recourse            7.944%        (815)         (815)     2016
                        Funding(3)                    senior notes
                                                                                        ------        ------
                                                                                          (573)         (573)
                                                                                        ======        ======
</Table>

---------------

(1) Net proceeds were primarily used to repay maturing long-term debt, redeem
    preferred interests of consolidated subsidiaries, repay short-term
    borrowings and other financing obligations and for other general corporate
    and investment purposes.
(2) During the third quarter of 2003, these preferred securities were
    reclassified as long-term debt as a result of adopting SFAS No. 150.
(3) Non-recourse debt reduced as a result of the sale of our interests in Mohawk
    River Funding IV and UCF in 2004.

     Aggregate maturities of the principal amounts of long-term financing
obligations for the next 5 years and in total thereafter are as follows (in
millions):

<Table>
<S>                                                           <C>
2004........................................................  $  310
2005........................................................     363
2006........................................................     654
2007........................................................      58
2008........................................................     476
Thereafter..................................................   3,468
                                                              ------
  Total long-term financing obligations, including current
     maturities.............................................  $5,329
                                                              ======
</Table>

     Included in the "thereafter" line of the table above are $375 million of
debentures that holders have an option to redeem prior to their stated maturity.
Of this amount, $75 million can be redeemed in 2005 and $300 million can be
redeemed in 2007.

     Coastal Finance I.  Coastal Finance I is a wholly owned business trust
formed in May 1998. Coastal Finance I completed a public offering of 12 million
mandatory redemption preferred securities for $300 million. Coastal Finance I
holds subordinated debt securities issued by us that it purchased with the

                                        92
<PAGE>

proceeds of the preferred securities offering. Cumulative quarterly
distributions are being paid on the preferred securities at an annual rate of
8.375% of the liquidation amount of $25 per preferred security. Coastal Finance
I's only source of income is interest earned on these subordinated debt
securities. This interest income is used to pay the obligations on Coastal
Finance I's preferred securities. The preferred securities are mandatorily
redeemable on the maturity date, May 13, 2038, and may be redeemed at our option
on or after May 13, 2003. The redemption price to be paid is $25 per preferred
security, plus accrued and unpaid distributions to the date of redemption. We
provide a guarantee of the payment of obligations of Coastal Finance I related
to its preferred securities to the extent Coastal Finance I has funds available.
During the third quarter of 2003, these preferred securities were reclassified
as long-term debt on our balance sheet as a result of adopting SFAS No. 150 (see
Notes 2 and 17). We began classifying dividends accrued on these preferred
securities as interest and debt expense in our financial statements after July
1, 2003.

  Credit Facilities

     In April 2003, El Paso entered into a new $3 billion revolving credit
facility, with a $1.5 billion letter of credit sublimit, which matures on June
30, 2005. This $3 billion revolving credit facility has a borrowing cost of
LIBOR plus 350 basis points, letter of credit fees of 350 basis points and
commitment fees of 75 basis points on unused amounts of the facility. This $3
billion revolving credit facility replaced El Paso's previous $3 billion
revolving credit facility. We are not a party to the $3 billion revolving credit
facility, although our subsidiaries, ANR and CIG, are borrowers under the
facility. As of December 31, 2003, there were $850 million of borrowings
outstanding and $1.2 billion of letters of credit issued under the $3 billion
revolving credit facility, none of which was borrowed or issued on our behalf.
Through September 30, 2004, El Paso had repaid $850 million of the debt
outstanding under the $3 billion revolving credit facility. As of October 8,
2004, El Paso's borrowing availability under this facility was $1.4 billion.

     Prior to December 2003, the $3 billion revolving credit facility and other
financing arrangements were also partially collateralized by various natural gas
and oil properties and production payments of El Paso and its subsidiaries. Upon
repayment of the Clydesdale financing arrangement in December 2003, the
production payment and these natural gas and oil properties were released from
the collateral package. Our equity interest in CIG became part of the collateral
package supporting the $3 billion revolving credit facility and the other
financing arrangements and CIG became a borrower under the facility. The $3
billion revolving credit facility and approximately $300 million of El Paso's
other financing arrangements are collateralized by our equity in ANR, CIG, WIC
and ANR Storage Company, along with other assets of El Paso.

     In April 2003, El Paso removed us as a borrower under its $1 billion 3-year
revolving credit and competitive advance facility, and as such, we were no
longer jointly and severally liable for any amounts outstanding under that
facility, which expired on August 4, 2003.

  Restrictive Covenants

     We have entered into debt instruments and guaranty agreements that contain
covenants such as limitations on debt levels, limitations on liens securing debt
and guarantees, limitations on mergers and on sales of assets, capitalization
requirements and dividend limitations. A breach of any of these covenants could
potentially accelerate our debt and other financial obligations and that of our
subsidiaries.

     One of the most significant debt covenants is that we must maintain a
minimum net worth of $850 million.

     Various other financing arrangements entered into by us and our
subsidiaries include covenants that require us to file financial statements
within specified time periods. Non-compliance with such covenants does not
constitute an automatic event of default. Instead, such agreements are subject
to acceleration when the indenture trustee or the holders of at least 25 percent
of the outstanding principal amount of any series of debt provides notice to the
issuer of non-compliance under the indentures. In that event, the non-compliance
can be cured by filing financial statements within specified periods of time
(between 30 and 90 days after receipt of notice depending on the particular
indenture) to avoid acceleration of repayment. The filing of our our first and
second quarter 2004 Forms 10-Q will cure the non-compliance caused by our
failure to file financial

                                        93
<PAGE>

statements. In addition, we have not received notice of the default caused by
our failure to file financial statements. In the event of an acceleration, we
may be unable to meet our payment obligations with respect to the related
indebtedness.

     In addition, our indentures associated with our public debt contain $5
million cross-acceleration provisions. These indentures state that should an
event of default occur resulting in the acceleration of other debt obligations
of us or our significant subsidiaries (as defined in the agreements) in excess
of $5 million, the long-term debt obligations containing such provisions could
be accelerated. The acceleration of our's and El Paso's debt would adversely
affect our liquidity position and in turn, our financial condition.

     In 2004, El Paso was required to obtain waivers on its $3 billion revolving
credit facility and other financing transactions (see Note 1) to address issues
related to its reserve revisions as further discussed in Note 1. These waivers
were subsequently extended and continue to be effective. In connection with
these waivers, El Paso received an extension until November 30, 2004 to file its
first and second quarter 2004 Forms 10-Q.

17. PREFERRED INTERESTS OF CONSOLIDATED SUBSIDIARIES

     In the past, we entered into financing transactions that have been
accomplished through the sale of preferred interests in consolidated
subsidiaries. Total amounts outstanding under these programs at December 31 were
as follows (in millions):

<Table>
<Caption>
                                                              2003   2002
                                                              ----   ----
<S>                                                           <C>    <C>
Coastal Securities Company Limited Preferred Stock..........  $ --   $100
Coastal Finance I...........................................    --    300
                                                              ----   ----
                                                              $ --   $400
                                                              ====   ====
</Table>

     Coastal Securities Company Limited Preferred Stock.  In 1996, Coastal
Securities Company Limited, our wholly owned subsidiary, issued 4 million shares
of preferred stock for $100 million to Cannon Investors Trust, which is an
entity comprised of a consortium of banks, to generate funds for investment and
general operating purposes. In December 2003, we redeemed the entire $100
million of the outstanding preferred interests and paid the accrued and unpaid
dividends.

     Additionally, during 2003 the outstanding amount of the preferred interest
in Coastal Finance I was reclassified as a long-term financing obligation with
the adoption of SFAS No. 150 (see Note 16).

18. COMMITMENTS AND CONTINGENCIES

  Legal Proceedings

     Grynberg.  A number of our subsidiaries were named defendants in actions
filed in 1997 brought by Jack Grynberg on behalf of the U.S. Government under
the False Claims Act. Generally, these complaints allege an industry-wide
conspiracy to underreport the heating value as well as the volumes of the
natural gas produced from federal and Native American lands, which deprived the
U.S. Government of royalties. The plaintiff in this case seeks royalties that he
contends the government should have received had the volume and heating value
been differently measured, analyzed, calculated and reported, together with
interest, treble damages, civil penalties, expenses and future injunctive relief
to require the defendants to adopt allegedly appropriate gas measurement
practices. No monetary relief has been specified in this case. These matters
have been consolidated for pretrial purposes (In re: Natural Gas Royalties Qui
Tam Litigation, U.S. District Court for the District of Wyoming, filed June
1997). Discovery is proceeding. Our costs and legal exposure related to these
lawsuits and claims are not currently determinable.

     Will Price (formerly Quinque).  A number of our subsidiaries are named as
defendants in Will Price, et al. v. Gas Pipelines and Their Predecessors, et
al., filed in 1999 in the District Court of Stevens County, Kansas. Plaintiffs
allege that the defendants mismeasured natural gas volumes and heating content
of natural

                                        94
<PAGE>

gas on non-federal and non-Native American lands and seek to recover royalties
that they contend they should have received had the volume and heating value of
natural gas produced from their properties been differently measured, analyzed,
calculated and reported, together with prejudgment and postjudgment interest,
punitive damages, treble damages, attorneys' fees, costs and expenses, and
future injunctive relief to require the defendants to adopt allegedly
appropriate gas measurement practices. No monetary relief has been specified in
this case. Plaintiffs' motion for class certification of a nationwide class of
natural gas working interest owners and natural gas royalty owners was denied on
April 10, 2003. Plaintiffs' were granted leave to file a Fourth Amended
Petition, which narrows the proposed class to royalty owners in wells in Kansas,
Wyoming and Colorado and removes claims as to heating content. A second class
action has since been filed as to the heating content claims. Our costs and
legal exposure related to these lawsuits and claims are not currently
determinable.

     MTBE.  In compliance with the 1990 amendments to the Clean Air Act, we use
the gasoline additive, methyl tertiary-butyl ether (MTBE), in some of our
gasoline. We have also produced, bought, sold and distributed MTBE. A number of
lawsuits have been filed throughout the U.S. regarding MTBE's potential impact
on water supplies. We and our subsidiaries are currently one of several
defendants in over 50 such lawsuits nationwide, which have been consolidated for
pre-trial purposes in multi-district litigation in the U.S. District Court for
the Southern District of New York. The plaintiffs generally seek remediation of
their groundwater, prevention of future contamination, a variety of compensatory
damages, punitive damages, attorney's fees, and court costs. Our costs and legal
exposure related to these lawsuits and claims are not currently determinable.

     Reserves.  We have been named as a defendant in a purported class action
claim styled, GlickenHaus & Co. et. al. v. El Paso Corporation, El Paso CGP
Company, et. al., filed in April 2004 in federal court in Houston. The
plaintiffs have additionally sued several individuals. The plaintiffs generally
allege that our reporting of oil and gas reserves was materially false and
misleading between February 2000 and February 2004. This lawsuit has been
consolidated with other purported securities class action lawsuits in Oscar S.
Wyatt et. al. v. El Paso Corporation et. al. pending in federal court in
Houston. Our costs and legal exposure related to this lawsuit and claims are not
currently determinable.

  Governmental Investigations

     Governmental and Other Reviews.  In October 2003, El Paso announced that
the SEC had authorized the Staff of the Fort Worth Regional Office to conduct an
investigation of certain aspects of our periodic reports filed with the SEC. The
investigation appears to be focused principally on our power plant contract
restructurings and the related disclosures and accounting treatment for the
restructured power contracts, including in particular the Eagle Point
restructuring transaction completed in 2002. We are cooperating with the SEC
investigation.

     Reserve Revisions.  In March 2004, El Paso received a subpoena from the SEC
requesting documents relating to El Paso's previously announced reserve
revision. El Paso and El Paso's Audit Committee have also received federal grand
jury subpoenas for documents regarding the reserve revision. We are assisting El
Paso and the Audit Committee in their efforts to cooperate with the SEC and the
U.S. Attorney investigations into the matter.

     CFTC Investigation.  In April 2004, our affiliates elected to voluntarily
cooperate with the Commodity Futures Trading Commission (CFTC) in connection
with the CFTC's industry-wide investigation of activities affecting the price of
natural gas in the fall of 2003. Specifically, our affiliates provided
information relating to storage reports provided to the Energy Information
Administration for the period of October 2003 through December 2003. On August
30, 2004, the CFTC announced they had completed the investigation and found no
evidence of wrongdoing.

     Iraq Oil Sales.  In September 2004, we received a subpoena from the grand
jury of the U.S. District Court for the Southern District of New York to produce
records regarding the United Nation's Oil for Food Program governing sales of
Iraqi oil. The subpoena seeks various records relating to transactions in oil of
Iraqi origin during the period from 1995 to 2003. Others in the energy industry
have received similar subpoenas.

                                        95
<PAGE>

     In addition to the above matters, we and our subsidiaries and affiliates
are named defendants in numerous lawsuits and governmental proceedings that
arise in the ordinary course of our business.

     For each of our outstanding legal matters, we evaluate the merits of the
case, our exposure to the matter, possible legal or settlement strategies and
the likelihood of an unfavorable outcome. If we determine that an unfavorable
outcome is probable and can be estimated, we establish the necessary accruals.
As this information becomes available, or other relevant developments occur, we
will adjust our accrual amounts accordingly. While there are still uncertainties
related to the ultimate costs we may incur, based upon our evaluation and
experience to date, we believe our current reserves are adequate. As of December
31, 2003, we had approximately $27 million accrued for all outstanding legal
matters.

  Environmental Matters

     We are subject to federal, state and local laws and regulations governing
environmental quality and pollution control. These laws and regulations require
us to remove or remedy the effect on the environment of the disposal or release
of specified substances at current and former operating sites. As of December
31, 2003, we had accrued approximately $131 million, including approximately
$129 million for expected remediation costs at current and former operated sites
and associated onsite, offsite and groundwater technical studies and
approximately $2 million for related environmental legal costs, which we
anticipate incurring through 2027. Of the $131 million, $114 million was
reserved for facilities we currently operate, and $17 million was reserved for
non-operating sites (facilities that are shut down or have been sold) including
superfund sites.

     Our reserve estimates range from approximately $131 million to
approximately $252 million. Our accrual represents a combination of two
estimation methodologies. First, where the most likely outcome can be reasonably
estimated, that cost has been accrued ($49 million). Second, where the most
likely outcome cannot be estimated, a range of costs is established ($82 million
to $203 million) and the lower end of the range has been accrued. By type of
site, our reserves are based on the following estimates of reasonably possible
outcomes.

<Table>
<Caption>
                                                              DECEMBER 31,
                                                                  2003
                                                              -------------
SITES                                                          LOW    HIGH
-----                                                         -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
Operating...................................................  $114    $180
Non-operating...............................................    12      64
Superfund...................................................     5       8
</Table>

     Below is a reconciliation of our accrued liability as of December 31, 2003
(in millions):

<Table>
<S>                                                           <C>
Balance as of January 1, 2003...............................  $ 62
Additions/adjustments for remediation activities............    12
Payments for remediation activities.........................   (10)
Other charges, net..........................................    67
                                                              ----
Balance as of December 31, 2003.............................  $131
                                                              ====
</Table>

     For 2004, we estimate that our total remediation expenditures will be
approximately $26 million. In addition, we expect to make capital expenditures
for environmental matters of approximately $29 million in the aggregate for the
years 2004 through 2008. These expenditures primarily relate to compliance with
clean air regulations.

     CERCLA Matters.  We have received notice that we could be designated, or
have been asked for information to determine whether we could be designated, as
a Potentially Responsible Party (PRP) with respect to 26 active sites under the
CERCLA or state equivalents. We have sought to resolve our liability as a PRP at
these sites through indemnification by third-parties and settlements which
provide for payment of our allocable share of remediation costs. As of December
31, 2003, we have estimated our share of the remediation costs at these sites to
be between $5 million and $8 million. Since the clean-up costs are estimates

                                        96
<PAGE>

and are subject to revision as more information becomes available about the
extent of remediation required, and because in some cases we have asserted a
defense to any liability, our estimates could change. Moreover, liability under
the federal CERCLA statute is joint and several, meaning that we could be
required to pay in excess of our pro rata share of remediation costs. Our
understanding of the financial strength of other PRPs has been considered, where
appropriate, in determining our estimated liabilities. Accruals for these issues
are included in the previously indicated estimates for Superfund sites.

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

     There are other regulatory rules and orders in various stages of adoption,
review and/or implementation, none of which we believe will have a material
impact on us.

     While the outcome of our outstanding rate and regulatory matters cannot be
predicted with certainty. We believe we have established appropriate reserves
for these matters. However, it is possible that new information or future
developments could require us to reassess our potential exposure and accruals
related to these matters.

  Commitments and Purchase Obligations

     Operating Leases.  We maintain operating leases in the ordinary course of
our business activities. These leases include those for office space and
operating facilities and office and operating equipment, and the terms of the
agreements vary from 2004 until 2031. As of December 31, 2003, our total
commitments under operating leases were approximately $156 million. Minimum
annual rental commitments under our operating leases at December 31, 2003, were
as follows:

<Table>
<Caption>
YEAR ENDING
DECEMBER 31,                                                  OPERATING LEASES
------------------------------------------------------------  ----------------
                                                              (IN MILLIONS)

<S>                                                           <C>
   2004.....................................................        $ 21
   2005.....................................................          20
   2006.....................................................          21
   2007.....................................................          18
   2008.....................................................          17
   Thereafter...............................................          59
                                                                    ----
          Total.............................................        $156
                                                                    ====
</Table>

     Rental expense on our operating leases for the years ended December 31,
2003, 2002 and 2001 was $27 million, $86 million and $39 million.

     Guarantees.  We are involved in various joint ventures and other ownership
arrangements that sometimes require additional financial support that results in
the issuance of financial and performance guarantees. In a financial guarantee,
we are obligated to make payments if the guaranteed party fails to make payments
under, or violates the terms of, the financial arrangement. In a performance
guarantee, we provide assurance that the guaranteed party will execute on the
terms of the contract. If they do not, we are required to perform on their
behalf. As of December 31, 2003, we had approximately $43 million of both
financial and performance guarantees, including $23 million of guarantees
related to our petroleum markets discontinued operations, not otherwise
reflected in our financial statements. The remaining guarantees are related to
our domestic and international power operations.

                                        97
<PAGE>

  Other Commercial Commitments

     We have various other commercial commitments and purchase obligations that
are not recorded on our balance sheet. At December 31, 2003, we had firm
commitments under transportation and storage capacity contracts of $331 million
and other purchase and capital commitments (including maintenance, engineering,
procurement and construction contracts) of $193 million. Included in other
purchase and capital commitments are unconditional purchase obligations entered
into by our pipelines for products and services totaling $212 million at
December 31, 2003. Our annual obligations under these agreements are $23 million
for each of the years 2004 through 2008, and $97 million in total thereafter.

19. RETIREMENT BENEFITS

  Pension and Retirement Benefits

     El Paso maintains a pension plan that covers substantially all of its U.S.
employees, including our employees except for employees of our coal and former
retail operations who are covered under separate plans.

     Prior to our merger with El Paso, we maintained defined benefit plans. Our
pension plans covered substantially all of our U.S. employees. On April 1, 2001,
our primary pension plan was merged into El Paso's existing cash balance plan.
Our employees who were participants in our primary plan on March 31, 2001
receive the greater of cash balance benefits or our plan benefits accrued
through March 31, 2006.

     We continue to maintain two other pension plans (Coastal Mart and Coastal
Coal) that are closed to new participants and provide benefits to former
employees of our previously discontinued coal and convenience store operations.
El Paso does not anticipate making any contributions to these pension plans in
2004.

     In 2001, El Paso offered an early retirement incentive program associated
with El Paso's pension plans for eligible employees of Coastal. This program
offered enhanced pension benefits to individuals who elected early retirement.
Net charges incurred in connection with this program were approximately $137
million in 2001. During 2003, there were $1 million in charges, that resulted
from employee terminations and our internal reorganization.

     El Paso also maintains a defined contribution plan covering its U.S.
employees, including our employees. We maintained a defined contribution plan
which was merged into El Paso's defined contribution plan on January 29, 2001.
Prior to May 1, 2002, El Paso matched 75 percent of participant basic
contributions up to 6 percent, with the matching contribution being made to the
plan's stock fund which participants could diversify at any time. After May 1,
2002, the plan was amended to allow for company matching contributions to be
invested in the same manner as that of participant contributions. Effective
March 1, 2003, El Paso suspended the matching contribution, but reinstituted it
again at a rate of 50 percent of participant basic contributions up to 6 percent
on July 1, 2003. Effective July 1, 2004, El Paso increased the matching
contribution to 75 percent of participant basic contributions up to 6 percent.
As a result of El Paso not being current on its SEC filings, the Plan Committee
temporarily suspended participants from making future contributions to or
transferring other investment funds to the El Paso Corporation Stock Fund
effective June 25, 2004. This temporary suspension does not affect the
participant's ability to maintain or transfer the investment that they may
currently have in the El Paso Corporation Stock Fund. Participants may continue
to sell stock currently held in the El Paso Corporation Stock Fund at their
discretion (subject to any insider trading restrictions). As soon as El Paso
completes its required SEC filings and is in compliance with the SEC
requirements, participants will be able to invest in the El Paso Corporation
Stock Fund again. El Paso is responsible for benefits accrued under its plans
and allocates the related costs to its affiliates.

  Other Postretirement Benefits

     In 2001, El Paso offered a one-time election to continue benefits in our
postretirement medical and life plans through an early retirement incentive
program for eligible employees of Coastal. Net charges incurred with this
program were approximately $65 million. El Paso reserves the right to change
these benefits.

                                        98
<PAGE>

     On December 8, 2003, the Medicare Prescription Drug, Improvement and
Modernization Act of 2003 was signed into law. Benefit obligations and costs
reported that are related to prescription drug coverage do not reflect the
impact of this legislation. Current accounting standards that are effective in
2004 may require changes to previously reported benefit information.

     In January 2001, following the merger, we changed the measurement date for
measuring our pension and other postretirement benefit obligations from December
31 to September 30. We made this change to conform our measurement date to the
date El Paso uses to measure pension and other postretirement benefit
obligations. The new method is consistent with the manner in which El Paso
gathers pension and other postretirement benefit information and will facilitate
ease of planning and reporting in a more timely manner. We believe this method
is preferable to the method previously employed. We accounted for this as a
change in accounting principle, and it had no material effect on retirement
benefit expense for the current or prior periods.

     Due to a corporate-wide restructuring during 2002, we no longer own Coastal
Mart, Inc. As a result, the 2002 and 2003 pension benefits shown below only
reflect benefits under our Coastal Coal, Inc. plans. Below is the change in
projected benefit obligation, change in plan assets and reconciliation of funded
status for our pension and other postretirement benefit plans. Our benefits are
presented and computed as of and for the twelve months ended September 30.

<Table>
<Caption>
                                                                              OTHER
                                                            PENSION      POSTRETIREMENT
                                                           BENEFITS         BENEFITS
                                                          -----------    ---------------
                                                          2003   2002     2003     2002
                                                          ----   ----    ------   ------
                                                                  (IN MILLIONS)
<S>                                                       <C>    <C>     <C>      <C>
Change in benefit obligation:
  Projected benefit obligation at beginning of period...  $ 79   $ 84     $102     $109
  Service cost..........................................     2      3       --        1
  Interest cost.........................................     4      5        6        8
  Participant contributions.............................    --     --        5        4
  Curtailment and special termination benefit...........    (8)    --       (6)      --
  Actuarial loss (gain).................................     7     10       10       (4)
  Projected benefits paid...............................    (3)    (3)     (17)     (16)
  Transfer of plan obligations..........................    --    (20)      --       --
                                                          ----   ----     ----     ----
  Projected benefit obligation at end of period.........  $ 81   $ 79     $100     $102
                                                          ====   ====     ====     ====
Change in plan assets:
  Fair value of plan assets at beginning of period......  $ 59   $ 97     $ 46     $ 40
  Actual return (loss) on plan assets...................     7     (8)       8       (1)
  Employer contributions................................    --     --       17       18
  Participant contributions.............................    --     --        5        4
  Projected benefits paid...............................    (3)    (3)     (17)     (15)
  Transfer of plan assets...............................    --    (27)      --       --
                                                          ----   ----     ----     ----
  Fair value of plan assets at end of period............  $ 63   $ 59     $ 59       46
                                                          ====   ====     ====     ====
Reconciliation of funded status:
  Fair value of plan assets at September 30.............  $ 63   $ 59     $ 59     $ 46
  Less: Projected benefit obligation at end of period...    81     79      100      102
                                                          ----   ----     ----     ----
  Funded status at September 30.........................   (18)   (20)     (41)     (56)
  Fourth quarter contributions and income...............    --     --        4        4
  Unrecognized net actuarial loss (gain)................    25     28      (24)     (29)
  Unrecognized prior service cost.......................    --      1       --       --
                                                          ----   ----     ----     ----
  Prepaid (accrued) benefit cost at December 31, .......  $  7   $  9     $(61)    $(81)
                                                          ====   ====     ====     ====
</Table>

                                        99
<PAGE>

<Table>
<Caption>
                                                                 PENSION
                                                                BENEFITS
                                                              -------------
                                                              2003    2002
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
Amounts recognized in the statement of financial position
  consist of:
  Prepaid benefit cost......................................  $ --    $ --
  Accrued benefit liability.................................   (18)    (11)
  Intangible asset..........................................    --       1
  Accumulated other comprehensive loss......................    25      19
                                                              ----    ----
  Net amount recognized at year-end.........................  $  7    $  9
                                                              ====    ====
  Other comprehensive loss attributable to change in
     additional minimum liability recognition...............  $  6    $ 19
                                                              ====    ====
</Table>

     Below is information for our pension plans that have accumulated benefit
obligations in excess of plan assets for the year ended December 31:

<Table>
<Caption>
                                                              2003    2002
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
Projected benefit obligation................................   $81     $79
Accumulated benefit obligation..............................    81      70
Fair value of plan assets...................................    63      59
</Table>

     The portion of our other postretirement benefits obligation included in
current liabilities was $3 million as of December 31, 2003 and 2002. For each of
the years ended December 31, the components of net benefit cost (income) are as
follows:

<Table>
<Caption>
                                                                             OTHER
                                               PENSION BENEFITS     POSTRETIREMENT BENEFITS
                                             --------------------   -----------------------
                                                        YEAR ENDED DECEMBER 31,
                                             ----------------------------------------------
                                             2003    2002    2001   2003     2002     2001
                                             ----    ----    ----   -----    -----    -----
                                                             (IN MILLIONS)
<S>                                          <C>     <C>     <C>    <C>      <C>      <C>
  Service cost.............................  $ 2     $ 3     $  5    $--      $ 1      $ 1
  Interest cost............................    5       5       20      6        8        9
  Expected return on plan assets...........   (6)     (7)     (55)    (2)      (2)      (2)
  Amortization of net actuarial gain
     (loss)................................   --      --       (9)    (1)      (1)      --
  Amortization of transition obligation....   --      --       (2)    --       --       --
  Curtailment and special termination
     benefits..............................    1      --      137     (6)      --       65
                                             ---     ---     ----    ---      ---      ---
     Net benefit cost (income).............  $ 2     $ 1     $ 96    $(3)     $ 6      $73
                                             ===     ===     ====    ===      ===      ===
</Table>

                                       100
<PAGE>

     We are required to recognize an additional minimum liability for pension
plans with an accumulated benefit obligation in excess of plan assets. We
recorded an other comprehensive loss of $6 million in 2003 and $19 million in
2002 related to the change in this additional minimum liability.

     Projected benefit obligations and net benefit cost are based on actuarial
estimates and assumptions. The following table details the weighted-average
actuarial assumptions used in determining the projected benefit obligation and
net benefit cost of our pension and other postretirement plans for 2003, 2002
and 2001:

<Table>
<Caption>
                                          PENSION BENEFITS      OTHER POSTRETIREMENT BENEFITS
                                        ---------------------   -----------------------------
                                        2003    2002    2001     2003        2002       2001
                                        -----   -----   -----   -------     ------     ------
                                              (PERCENT)                   (PERCENT)
<S>                                     <C>     <C>     <C>     <C>         <C>        <C>
Assumptions related to benefit
  obligations at September 30:
  Discount rate.......................   6.00    6.75             6.00       6.75
  Rate of compensation increase.......           4.00
Assumptions related to benefit costs
  for the year ended December 31:
  Discount rate.......................   6.75    7.25    7.75     6.75       7.25       7.75
  Expected return on plan assets(1)...   8.80    8.80   10.00     7.50       7.50       7.50
  Rate of compensation increase.......   4.00    4.00    4.00
</Table>

---------------

(1) The expected return on plan assets is a pre-tax rate (before a tax rate of
    38 percent on postretirement benefits) that is primarily based on an
    expected risk-free investment return, adjusted for historical risk premiums
    and specific risk adjustments associated with our debt and equity
    securities. These expected returns were then weighted based on our target
    asset allocations of our investment portfolio. For 2004, the assumed
    expected return on assets for pension benefits will be reduced to 8.50%.

     Actuarial estimates for our other postretirement benefits plans assumed a
weighted-average annual rate of increase in the per capita costs of covered
health care benefits of 10.0 percent in 2003, gradually decreasing to 5.5
percent by the year 2008. Assumed health care cost trends have a significant
effect on the amounts reported for other postretirement benefit plans. A one
percentage point change in assumed health care cost trends would have the
following effects as of September 30:

<Table>
<Caption>
                                                              2003    2002
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
One percentage point increase:
  Aggregate of service cost and interest cost...............  $ --    $  --
  Accumulated postretirement benefit obligation.............     3        2
One percentage point decrease:
  Aggregate of service cost and interest cost...............  $ --    $  --
  Accumulated postretirement benefit obligation.............    (3)      (2)
</Table>

  Plan Assets

     The following table provides the target and actual asset allocations in our
pension and other postretirement benefit plans as of September 30:

<Table>
<Caption>
                                    PENSION PLANS                    OTHER POSTRETIREMENT PLANS
                         ------------------------------------   ------------------------------------
ASSET CATEGORY           TARGET   ACTUAL 2003    ACTUAL 2002    TARGET   ACTUAL 2003    ACTUAL 2002
--------------           ------   ------------   ------------   ------   ------------   ------------
                                      (PERCENT)                              (PERCENT)
<S>                      <C>      <C>            <C>            <C>      <C>            <C>
Equity securities(1)...    70          70             66          65          28             --
Debt securities........    30          29             33          35          58             --
Other..................    --           1              1          --          14            100
                          ---         ---            ---         ---         ---            ---
  Total................   100         100            100         100         100            100
                          ===         ===            ===         ===         ===            ===
</Table>

---------------

(1) Actuals for our pension plans include $1 million (2.1 percent of total
    assets) and $2 million (2.6 percent of total assets) of El Paso's common
    stock at September 30, 2003 and September 30, 2002.

                                       101
<PAGE>

     The primary investment objective of our plans is to ensure, that over the
long-term life of the plans, an adequate pool of sufficiently liquid assets to
support the benefit obligations to participants, retirees and beneficiaries
exists. In meeting this objective, the plans seek to achieve a high level of
investment return consistent with a prudent level of portfolio risk. Investment
objectives are long-term in nature covering typical market cycles of three to
five years. Any shortfall of investment performance compared to investment
objectives is the result of general economic and capital market conditions.

     In late 2003, we modified our target asset allocations for our other
postretirement plans to increase our equity allocation to 65 percent of total
plan assets and as a result, the actual assets as of September 30, 2003 had not
yet been adjusted to reflect this allocation change. For 2004, we modified our
target and actual asset allocations for our pension plans to reduce our equity
allocation to 60 percent of total plan assets. Correspondingly, our 2004
assumption related to the expected return on plan assets will be reduced from
8.80% to 8.50% to reflect this change.

20. SEGMENT INFORMATION

     We segregate our business activities into four operating segments:
Pipelines, Production, Field Services and Merchant Energy. These segments are
strategic business units that provide a variety of energy products and services.
They are managed separately as each business unit requires different technology
and marketing strategies. Our Production segment information for the years ended
December 31, 2002 and 2001 has been restated as further discussed in Note 1. In
2002 and 2003, we reclassified our petroleum markets and coal mining operations
from our Merchant Energy segment to discontinued operations in our financial
statements. Merchant Energy's operating results for all periods reflect this
change.

     Our Pipelines segment provides natural gas transmission, storage and
related services, in the U.S. We conduct our activities primarily through three
wholly owned and a partially owned interstate transmission systems along with
four underground natural gas storage entities.

     Our Production segment is engaged in the exploration for, and the
acquisition, development and production of natural gas, oil and natural gas
liquids, primarily in North America. In the U.S., Production has onshore and
coal seam operations and properties in 10 states and offshore operations and
properties in federal and state waters in the Gulf of Mexico. Internationally,
we have exploration and production rights in Australia, Bolivia, Brazil, Canada,
Hungary and Indonesia.

     Our Field Services segment provides customers with processing and gathering
services. Field Services' assets are primarily located in the south Louisiana
region.

     Our Merchant Energy segment owns and has interests in domestic and
international power. We own or have interests in 19 power plants in 8 countries.

     We had no customers whose revenues exceeded 10 percent of our total
revenues in 2003, 2002 and 2001.

                                       102
<PAGE>

     We use EBIT to assess the operating results and effectiveness of our
business segments. We define EBIT as net income (loss) adjusted for (i) items
that do not impact our income (loss) from continuing operations, such as
extraordinary items, discontinued operations and the impact of accounting
changes, (ii) income taxes, (iii) interest and debt expense and (iv)
distributions on preferred interests of consolidated subsidiaries. Our business
operations consist of both consolidated businesses as well as substantial
investments in unconsolidated affiliates. We believe EBIT is useful to our
investors because it allows them to more effectively evaluate the performance of
all of our businesses and investments. Also, we exclude interest and debt
expense and distributions on preferred interests of consolidated subsidiaries so
that investors may evaluate our operating results without regard to our
financing methods or capital structure. EBIT may not be comparable to measures
used by other companies. Additionally, EBIT should be considered in conjunction
with net income and other performance measures such as operating income or
operating cash flow. Below is a reconciliation of our EBIT to our income (loss)
from continuing operations for each of the three years ended December 31:

<Table>
<Caption>
                                                                    2002          2001
                                                        2003     (RESTATED)    (RESTATED)
                                                        -----    ----------    ----------
                                                                  (IN MILLIONS)
<S>                                                     <C>      <C>           <C>
Total EBIT............................................  $ 579      $ 890         $ (63)
Interest and debt expense.............................   (403)      (421)         (420)
Affiliated interest expense, net......................    (41)        (9)          (46)
Distributions on preferred interests of consolidated
  subsidiaries........................................    (17)       (35)          (51)
Income taxes..........................................     57       (109)           87
                                                        -----      -----         -----
          Income (loss) from continuing operations....  $ 175      $ 316         $(493)
                                                        =====      =====         =====
</Table>

                                       103
<PAGE>

     The following tables reflect our segment results as of and for each of the
three years ended December 31:

<Table>
<Caption>
                                                                 SEGMENTS
                                               AS OF OR FOR THE YEAR ENDED DECEMBER 31, 2003
                                  -----------------------------------------------------------------------
                                  REGULATED              UNREGULATED
                                  ---------   ---------------------------------
                                                            FIELD      MERCHANT   CORPORATE AND
                                  PIPELINES   PRODUCTION   SERVICES     ENERGY      OTHER(1)       TOTAL
                                  ---------   ----------   --------    --------   -------------   -------
                                                               (IN MILLIONS)
<S>                               <C>         <C>          <C>         <C>        <C>             <C>
Revenues from external customers
  Domestic......................   $  915       $  742(2)    $328       $  168       $    --      $ 2,153
  Foreign.......................        2           56          2           77            --          137
Intersegment revenue............        1          112         26           (7)          (48)          84(3)
Operation and maintenance.......      246          176         20          105            (7)         540
Depreciation, depletion and
  amortization..................      108          377          7           15            10          517
Ceiling test charges............       --          109         --           --            --          109
Loss (gain) on long-lived
  assets........................      (11)          93        (13)          28            --           97
Operating income (loss).........   $  397       $   80       $ 41       $    7       $    (5)     $   520
Earnings (losses) from
  unconsolidated affiliates.....       75           10        (93)          (6)            2          (12)
Other income....................       32            2         --           13            19           66
Other expense...................       (4)          --         --           10            (1)           5
                                   ------       ------       ----       ------       -------      -------
EBIT............................   $  500       $   92       $(52)      $   24       $    15      $   579
                                   ======       ======       ====       ======       =======      =======
Assets of continuing
  operations(4)
  Domestic......................    5,271        1,950        224        1,556           668        9,669
  Foreign.......................       --          671         --          601            99        1,371
Capital expenditures and
  investments in unconsolidated
  affiliates, net(5)............      192          728         14           (9)          (12)         913
Total investments in
  unconsolidated affiliates.....      397           52         54          804             5        1,312
</Table>

---------------
(1) Includes our Corporate and 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
    record an intersegment revenue and operation and maintenance expense
    elimination, which is included in the "Corporate and Other" column, to
    remove intersegment transactions.
(2) Revenues from external customers include gains and losses related to our
    hedging of price risk associated with our natural gas and oil production.
(3) Relates to intercompany activities between our continuing operating segments
    and our discontinued petroleum markets operations.
(4) Excludes assets of discontinued operations of $1.4 billion (see Note 10).
(5)Amounts are net of third party reimbursements of our capital expenditures and
   returns of invested capital.

                                       104
<PAGE>

<Table>
<Caption>
                                                                  SEGMENTS
                                               AS OF OR FOR THE YEAR ENDED DECEMBER 31, 2002
                                 --------------------------------------------------------------------------
                                 REGULATED              UNREGULATED
                                 ---------   ---------------------------------
                                             PRODUCTION    FIELD      MERCHANT   CORPORATE AND     TOTAL
                                 PIPELINES   (RESTATED)   SERVICES     ENERGY      OTHER(1)      (RESTATED)
                                 ---------   ----------   --------    --------   -------------   ----------
                                                               (IN MILLIONS)
<S>                              <C>         <C>          <C>         <C>        <C>             <C>
Revenues from external
  customers
  Domestic.....................   $  901       $1,092(2)   $ 404       $1,072        $  --        $ 3,469
  Foreign......................        3           71          3          154           --            231
Intersegment revenue...........       30           95         53          (22)         (30)           126(3)
Operation and maintenance
  expenses.....................      235          243         45          239           15            777
Depreciation, depletion and
  amortization.................      116          468         14           19           13            630
Ceiling test charges...........       --          521         --           --           --            521
Loss (gain) on long-lived
  assets.......................      (12)           6        (21)          18            2             (7)
Operating income (loss)........   $  419       $  (57)     $  68       $  385        $ (38)       $   777
Earnings (losses) from
  unconsolidated affiliates....      105            4        (53)          57           --            113
Other income...................       16            1         --           25           28             70
Other expense..................       (3)          --         --          (58)          (9)           (70)
                                  ------       ------      -----       ------        -----        -------
EBIT...........................   $  537       $  (52)     $  15       $  409        $ (19)       $   890
                                  ======       ======      =====       ======        =====        =======
Assets of continuing
  operations(4)
  Domestic.....................    5,128        2,203        451        1,748          528         10,058
  Foreign......................       47          578         14          636          157          1,432
Capital expenditures and
  investments in unconsolidated
  affiliates, net(5)...........      252        1,124         20          (26)         405          1,775
Total investments in
  unconsolidated affiliates....      404           90        143          851           17          1,505
</Table>

---------------
(1) Includes our Corporate and 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
    record an intersegment revenue and operation and maintenance expense
    elimination, which is included in the "Corporate and Other" column, to
    remove intersegment transactions.
(2) Revenues from external customers include gains and losses related to our
    hedging of price risk associated with our natural gas and oil production.
(3) Relates to intercompany activities between our continuing operating segments
    and our discontinued petroleum markets operations.
(4) Excludes assets of discontinued operations of $4.1 billion (see Note 10).
(5)Amounts are net of third party reimbursements of our capital expenditures and
   returns of invested capital.

                                       105
<PAGE>

<Table>
<Caption>
                                                                    SEGMENTS
                                                  AS OF OR FOR THE YEAR ENDED DECEMBER 31, 2001
                                     -----------------------------------------------------------------------
                                     REGULATED             UNREGULATED
                                     ---------   --------------------------------    CORPORATE
                                                 PRODUCTION    FIELD     MERCHANT       AND         TOTAL
                                     PIPELINES   (RESTATED)   SERVICES    ENERGY     OTHER(1)     (RESTATED)
                                     ---------   ----------   --------   --------    ---------    ----------
                                                                  (IN MILLIONS)
<S>                                  <C>         <C>          <C>        <C>         <C>          <C>
Revenues from external customers
  Domestic.........................   $  982       $1,772(2)    $822      $   43      $  355       $ 3,974
  Foreign..........................        2           46          4          --          --            52
Intersegment revenue...............       70          (35)        68          --        (165)          (62)(3)
Operation and maintenance..........      278          241         66          36         198           819
Merger-related costs...............      192           45         13          17         520           787
Depreciation, depletion and
  amortization.....................      137          658         15           5          21           836
Ceiling test charges...............       --          537         --          --          --           537
Loss on long-lived assets..........       22           16         --          21          10            69
Operating income (loss)............   $  195       $  158       $ 56      $  (41)     $ (714)      $  (346)
Earnings from unconsolidated
  affiliates.......................       98            4         14         104          --           220
Other income.......................        8            3          2          47          21            81
Other expense......................       (9)          (2)        --          (2)         (5)          (18)
                                      ------       ------       ----      ------      ------       -------
EBIT...............................   $  292       $  163       $ 72      $  108      $ (698)      $   (63)
                                      ======       ======       ====      ======      ======       =======
Assets of continuing operations(4)
  Domestic.........................    5,347        3,725        584         395         444        10,495
  Foreign..........................       14          529         17         894          32         1,486
Capital expenditures and
  investments in unconsolidated
  affiliates, net(5)...............      421        1,814         53         (12)        290         2,566
Total investments in unconsolidated
  affiliates.......................      547           86        217         931          17         1,798
</Table>

---------------

(1) Includes our Corporate and 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
    record an intersegment revenue and operation and maintenance elimination,
    which is included in the "Corporate and Other" column, to remove
    intersegment transactions.
(2) Revenues from external customers include gains and losses related to our
    hedging of price risk associated with our natural gas and oil production.
(3) Relates to intercompany activities between our continuing operating segments
    and our discontinued petroleum markets operations.
(4) Excludes assets of discontinued operations of $4.8 billion.
(5)Amounts are net of third party reimbursements of our capital expenditures and
   returns of invested capital.

21. SUPPLEMENTAL CASH FLOW INFORMATION

     The following table contains supplemental cash flow information from
continuing operations for each of the three years ended December 31 for interest
and taxes, which were reflected in the asset and liability changes in our
statements of cash flows:

<Table>
<Caption>
                                                              2003    2002    2001
                                                              ----    ----    ----
                                                                 (IN MILLIONS)
<S>                                                           <C>     <C>     <C>
Interest paid, net of amounts capitalized...................  $586    $502    $565
Income tax payments (refunds)...............................    92     (23)     82
</Table>

                                       106
<PAGE>

22. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES AND TRANSACTIONS
    WITH RELATED PARTIES

     We hold investments in various unconsolidated affiliates which are
accounted for using the equity method of accounting. Our principal equity method
investees are interstate pipelines and power generation plants. Our investment
balance was less than our equity in the net assets of these investments as of
December 31, 2003 by $37 million, and greater than our equity in the net assets
of these investments in 2002 by $46 million. These differences primarily relate
to unamortized purchase price adjustments, net of asset impairment charges. Our
net ownership interest, investments in and advances to our unconsolidated
affiliates are as follows as of December 31:

<Table>
<Caption>
                                                                         INVESTMENTS
                                                            NET      -------------------    ADVANCES
                                              TYPE OF    OWNERSHIP               2002      -----------
                                 COUNTRY     ENTITIES    INTEREST     2003    (RESTATED)   2003   2002
                                ---------   -----------  ---------   ------   ----------   ----   ----
                                                         (PERCENT)             (IN MILLIONS)
<S>                             <C>         <C>          <C>         <C>      <C>          <C>    <C>
Domestic:
  Bastrop Company(1)..........                LLC(2)        50       $   73     $  121     $ --   $ --
  Great Lakes Gas
    Transmission(3)...........                 LP(5)        50          325        312       --     --
  Midland Cogeneration
    Venture(4)................                 LP(5)        44          348        316       --     --
  Noric Holdings I............                LLC(2)        38           52         90       --     --
  Other Domestic
    Investments...............                           various        130        253       22     21
                                                                     ------     ------     ----   ----
    Total domestic............                                          928      1,092       22     21
                                                                     ------     ------     ----   ----
Foreign:
  EGE Fortuna.................   Panama     Corporation     25           59         61       --     --
  EGE Itabo...................  Dominican   Corporation     25           87         87       --     --
                                Republic
  Habibullah Power............  Pakistan      LLC(2)        50           48         57       90     99
  Saba Power Company..........  Pakistan      LLC(2)        94           59         55       --     --
  Other Foreign Investments...                           various        131        153       13     50
                                                                     ------     ------     ----   ----
    Total foreign.............                                          384        413      103    149
                                                                     ------     ------     ----   ----
         Total investments in and advances to unconsolidated
           affiliates.............................................   $1,312     $1,505     $125   $170
                                                                     ======     ======     ====   ====
</Table>

---------------
(1) In June 2004, we completed the sale of our interest in this investment.
(2) LLC represents Limited Liability Company.
(3) Includes a 46 percent general partner interest in Great Lakes Gas
    Transmission Limited Partnership and a 4 percent limited partner interest
    through our ownership in Great Lakes Gas Transmission Company.
(4) Our ownership interest consists of a 38.1 percent general partner interest
    and a 5.4 percent limited partner interest.
(5) LP represents Limited Partnership.

                                       107
<PAGE>

     Earnings (losses) from our unconsolidated affiliates are as follows for
each of the three years ended December 31:

<Table>
<Caption>
                                                                    2002          2001
                                                        2003     (RESTATED)    (RESTATED)
                                                        -----    ----------    ----------
                                                                  (IN MILLIONS)
<S>                                                     <C>      <C>           <C>
Alliance Pipeline Limited Partnership(1)..............  $   1       $ 21          $ 23
Bastrop Company.......................................     (6)        (5)           --
Eagle Point Cogeneration Partnership(2)...............     --         --            22
EGE Fortuna...........................................      3          6             3
EGE Itabo.............................................      1         (2)            5
Great Lakes Gas Transmission..........................     57         63            55
Habibullah Power......................................     (1)        10             2
Midland Cogeneration Venture..........................     32         28            23
Noric Holdings I......................................     10          4             4
Saba Power Company....................................      4          7            --
Other.................................................    (11)        16            49
                                                        -----       ----          ----
     Proportional share of income of investee.........     90        148           186
Impairment charges and gains and losses on sales of
  investments.........................................   (128)       (47)           10
Other.................................................     26         12            24
                                                        -----       ----          ----
          Total earnings (loss) from unconsolidated
            affiliates................................  $ (12)      $113          $220
                                                        =====       ====          ====
</Table>

---------------

(1) We sold our interest in this investment.
(2) Consolidated in January 2002.

     Our impairment charges and gains and losses on sales of equity investments
during 2003, 2002 and 2001 consisted of the following:

<Table>
<Caption>
                                          PRE-TAX                   CAUSE OF IMPAIRMENTS
INVESTMENT                              GAIN (LOSS)                    OR GAIN (LOSS)
----------                             -------------                --------------------
                                       (IN MILLIONS)
<S>                                    <C>             <C>
2003
Bastrop Company......................      $ (43)      Decision to sell investment
Dauphin Island Gathering/Mobile Bay
Processing...........................        (86)      Decline in the investments' fair value based on
                                                       the devaluation of the underlying assets
Other investments....................          1
                                           -----
                                           $(128)
                                           =====
2002
Aux Sable NGL........................      $ (47)      Sale of investment
                                           =====
2001
Deepwater Investors..................      $  13       Sale of investment
Other investments....................         (3)
                                           -----
                                           $  10
                                           =====
</Table>

                                       108
<PAGE>

     Below is summarized financial information of our proportionate share of
unconsolidated affiliates. This information includes affiliates in which we hold
a less than 50 percent interest as well as those in which we hold a greater than
50 percent interest. We received distributions and dividends of $98 million,
$127 million and $136 million in 2003, 2002 and 2001, which includes $17
million, $6 million and $14 million of returns of capital, in 2003, 2002 and
2001 from our investments. Our proportional shares of the unconsolidated
affiliates in which we hold a greater than 50 percent interest had net income of
$20 million, $25 million and $40 million in 2003, 2002 and 2001 and total assets
of $536 million and $382 million as of December 31, 2003 and 2002.

<Table>
<Caption>
                                                              YEAR ENDED DECEMBER 31,
                                                              -----------------------
                                                              2003     2002     2001
                                                              -----    -----    -----
                                                                    (UNAUDITED)
                                                                   (IN MILLIONS)
<S>                                                           <C>      <C>      <C>
Operating results data:
  Operating revenues........................................  $807     $799     $964
  Operating expenses........................................   590      542      632
  Income from continuing operations.........................    90      125      186
  Net income................................................    90      148      186
</Table>

<Table>
<Caption>
                                                                    DECEMBER 31,
                                                                --------------------
                                                                             2002
                                                                 2003     (RESTATED)
                                                                ------    ----------
                                                                    (UNAUDITED)
                                                                   (IN MILLIONS)
<S>                                                             <C>       <C>
Financial position data:
  Current assets............................................    $  468      $  438
  Non-current assets........................................     2,386       2,538
  Short-term debt...........................................        99          92
  Other current liabilities.................................       249         240
  Long-term debt............................................       905       1,015
  Other non-current liabilities.............................       181         170
  Minority interest.........................................        71          --
  Equity in net assets......................................     1,349       1,459
</Table>

     The following table shows revenues and charges from our unconsolidated
affiliates:

<Table>
<Caption>
                                                               2003     2002     2001
                                                              ------   ------   ------
                                                                   (IN MILLIONS)
<S>                                                           <C>      <C>      <C>
Revenues....................................................  $1,093   $1,616   $1,889
Cost of sales...............................................      87      178      227
Reimbursement for operating expenses........................       4        3       11
Charges from affiliates.....................................     331      354      335
Other income................................................       6        6        8
</Table>

 Related Party Transactions

     We enter into transactions with other El Paso subsidiaries and
unconsolidated affiliates in the ordinary course of business to transport, sell
and purchase natural gas and liquids and various contractual agreements for
trading activities. In February 2001, we transferred our natural gas and power
trading activities to El Paso Merchant Energy Company, an affiliate and
subsidiary of El Paso, in exchange for a 22 percent interest in El Paso Merchant
Energy, L.P. The transfer was based on estimated fair value of contracts
transferred, and the investment was accounted for on a cost basis. In September
2001, we redeemed this interest. As a result, operational related party
transactions that had previously been with an unconsolidated affiliate are now
with an affiliate. For the years ended December 31, 2003, 2002 and 2001 we
recognized revenues with El Paso Merchant Energy L.P. of $750 million, $1,085
million and $1,555 million which were primarily with our Production segment. We
had cost of sales of $27 million, $102 million and $85 million with El Paso
Merchant Energy L.P. for 2003, 2002 and 2001.

                                       109
<PAGE>

     El Paso allocates a portion of its general and administrative expenses to
us. The allocation is based on the estimated level of effort devoted to our
operations and the relative size of our EBIT, gross property and payroll. For
the years ended December 2003, 2002 and 2001, the annual charges were $152
million, $146 million and $193 million. During 2003, 2002 and 2001 El Paso
Natural Gas Company and Tennessee Gas Pipeline Company allocated payroll and
other expenses to us associated with our shared pipeline services. The allocated
expenses are based on the estimated level of staff and their expenses to provide
the services. For the years ended December 2003, 2002 and 2001 the annual
charges were $48 million, $40 million and $34 million. El Paso also provides our
production segment administrative and other shared production services and
allocated $122 million, $155 million and $102 million in 2003, 2002 and 2001. We
believe the allocation methods are reasonable.

     We participate in El Paso's cash management program which matches
short-term cash surpluses and needs of its participating affiliates, thus
minimizing total borrowing from outside sources. We have historically and
consistently borrowed cash from El Paso under this program. As of December 31,
2003 and December 31, 2002, we had borrowed $906 million and $2,374 million. The
market rate of interest as of December 31, 2003 was 2.8% and at December 31,
2002, it was 1.5%. On December 31, 2003, El Paso's Board of Directors authorized
a capital contribution of $1.5 billion to us. In addition, we had a demand note
receivable with El Paso of $275 million at December 31, 2003, at an interest
rate of 1.7%. At December 31, 2002, the demand note receivable was $199 million
at an interest rate of 2.2%.

     At December 31, 2003 and December 31, 2002, we had accounts and notes
receivable from related parties of $167 million and $322 million. In addition,
we had a non-current note receivable from a related party of $127 million and
$126 million included in other non-current assets at December 31, 2003 and at
December 31, 2002.

     At December 31, 2003 and December 31, 002, we had other accounts payable to
related parties of $110 million and $87 million.

     In 2003, El Paso made a capital contribution of $24 million to us. This
contribution is reflected in our stockholder's equity statement as an increase
in our additional paid in capital.

     In March 2002, we acquired assets with a net book value, net of deferred
taxes, of approximately $8 million from El Paso.

     Additionally, we sold natural gas and oil properties to another subsidiary
of El Paso in 2002. Net proceeds from these sales were $404 million, and because
this sale involved entities under the common control of El Paso, we did not
recognize a gain or loss on the properties sold. The proceeds originally
exceeded the net book value by $32 million which we recorded as an increase to
paid in capital. As a result of the restatement of our natural gas and oil
reserve estimates, we restated the net book value of the properties sold and
accordingly increased our additional paid in capital by $138 million, bringing
the total adjustment to equity for this sale to $170 million.

     In November 2002, we sold our stock in Coastal Mart, Inc., one of our
wholly-owned subsidiaries, to El Paso Remediation Company, a wholly owned
subsidiary of El Paso. We recorded a receivable of $42 million, which was based
on the book value of the company (since the sale occurred between entities under
common control). We did not recognize a gain or loss on this sale.

     In December 2002, El Paso contributed to us its interest in one of its
subsidiaries to us that had a book value of $139 million. At the time it was
contributed, we reflected the contribution in our 2002 balance sheet as minority
interest of consolidated subsidiaries. During 2003, we revised our 2002 balance
sheet to reclassify this contribution from minority interest to paid in capital.
This revision had no impact on our statements of income, cash flows or
comprehensive income.

                                       110
<PAGE>

23. SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

     Financial information by quarter, as restated to reflect the impacts of the
revisions of our natural gas and oil reserves and other resulting matters as
further described in Note 1 is summarized below:

<Table>
<Caption>
                                                                QUARTERS ENDED
                                            ------------------------------------------------------
                                             MARCH 31     JUNE 30     SEPTEMBER 30
                                            (RESTATED)   (RESTATED)    (RESTATED)     DECEMBER 31     TOTAL
                                            ----------   ----------   -------------   ------------   -------
                                                                     (IN MILLIONS)
<S>                                         <C>          <C>          <C>             <C>            <C>
2003(1)
  Operating revenues......................    $  738       $ 610          $506           $ 520       $ 2,374
  Ceiling test charges....................         1          20            80               8           109
  Loss (gain) on long-lived assets........         8         (25)            5             109            97
  Operating income (loss).................       276         207            45              (8)          520
  Income (loss) from continuing
     operations...........................       136          32           (20)             27           175
  Discontinued operations, net of income
     taxes................................      (222)       (916)          (49)           (110)       (1,297)
  Cumulative effect of accounting changes,
     net of income taxes..................       (12)         --            --              --           (12)
  Net loss................................       (98)       (884)          (69)            (83)       (1,134)
</Table>

<Table>
<Caption>
                                                                QUARTERS ENDED
                                            ------------------------------------------------------
                                             MARCH 31     JUNE 30     SEPTEMBER 30    DECEMBER 31      TOTAL
                                            (RESTATED)   (RESTATED)    (RESTATED)      (RESTATED)    (RESTATED)
                                            ----------   ----------   -------------   ------------   ----------
                                                                       (IN MILLIONS)
<S>                                         <C>          <C>          <C>             <C>            <C>
2002(1)
  Operating revenues......................    $1,697       $ 758          $669           $ 702        $ 3,826
  Ceiling test charges....................         4         514            --               3            521
  Loss (gain) on long-lived assets........       (11)        (10)            1              13             (7)
  Operating income (loss).................       597        (198)          156             222            777
  Income (loss) from continuing
     operations...........................       332        (271)          112             143            316
  Discontinued operations, net of income
     taxes................................        60        (116)          (93)           (216)          (365)
  Cumulative effect of accounting changes,
     net of income taxes..................        --          14            --              --             14
  Net income (loss).......................       392        (373)           19             (73)           (35)
</Table>

---------------
(1) Our petroleum markets and coal mining operations are classified as
    discontinued operations. See Note 10 for further discussion.

                                       111
<PAGE>

24. SUPPLEMENTAL NATURAL GAS AND OIL OPERATIONS (UNAUDITED)

     Our Production segment is engaged in the exploration for and the
acquisition, development and production of natural gas, oil and natural gas
liquids, primarily in North America. In the U.S., we have onshore and coal seam
operations and properties in 10 states and offshore operations and properties in
federal and state waters in the Gulf of Mexico. Internationally, we have
exploration and production rights in Australia, Bolivia, Brazil, Canada, Hungary
and Indonesia.

     Capitalized costs relating to natural gas and oil producing activities and
related accumulated depreciation, depletion and amortization were as follows at
December 31 (in millions):

<Table>
<Caption>
                                    UNITED                             OTHER
                                    STATES   CANADA(1)   BRAZIL    COUNTRIES(2)     WORLDWIDE
                                    ------   ---------   ------   ---------------   ---------
<S>                                 <C>      <C>         <C>      <C>               <C>
2003
  Natural gas and oil properties:
     Costs subject to
       amortization...............  $6,831    $  861      $146          $47          $7,885
     Costs not subject to
       amortization...............     119       146       117            7             389
                                    ------    ------      ----          ---          ------
                                     6,950     1,007       263           54           8,274
Less accumulated depreciation,
  depletion and amortization......   5,295       650        58           20           6,023
                                    ------    ------      ----          ---          ------
Net capitalized costs(3)..........  $1,655    $  357      $205          $34          $2,251
                                    ======    ======      ====          ===          ======
2002 (Restated)
  Natural gas and oil properties:
     Costs subject to
       amortization...............  $6,353    $  608      $ --          $ 8          $6,969
     Costs not subject to
       amortization...............     314       177        --           --             491
                                    ------    ------      ----          ---          ------
                                     6,667       785        --            8           7,460
Less accumulated depreciation,
  depletion and amortization......   5,085       456        --            3           5,544
                                    ------    ------      ----          ---          ------
Net capitalized costs.............  $1,582    $  329      $ --          $ 5          $1,916
                                    ======    ======      ====          ===          ======
</Table>

---------------
(1) As of September 2004, we have sold our production operations in Canada.
(2) Includes international operations in Hungary and Indonesia. As of September
    2004, we have sold substantially all of our operations in Indonesia.
(3) In January 1, 2003, we adopted SFAS No. 143. Included in our net capitalized
    costs at December 31, 2003 are SFAS No. 143 asset values of $77 million
    primarily for the U.S. Prior period presentation was not adjusted as amounts
    were adjusted through a one-time cumulative adjustment which is further
    discussed on Note 2.

                                       112
<PAGE>

     Costs incurred in natural gas and oil producing activities, whether
capitalized or expensed, were as follows at December 31 (in millions):

<Table>
<Caption>
                                      UNITED                            OTHER
                                      STATES   CANADA(1)   BRAZIL   COUNTRIES(2)    WORLDWIDE
                                      ------   ---------   ------   -------------   ---------
                                                           (IN MILLIONS)
<S>                                   <C>      <C>         <C>      <C>             <C>
2003
  Property acquisition costs
     Proved properties..............  $   --     $  1       $--          $--         $    1
     Unproved properties............       9       10         4           --             23
  Exploration costs(3)..............     216       44        95           11            366
  Development costs(3)(4)...........     270       57        --            2            329
                                      ------     ----       ---          ---         ------
          Total costs expended......  $  495     $112       $99          $13         $  719
  Plus: Asset Retirement Obligation
     costs(4).......................      77       --        --           --             77
  Less: Actual Retirement
     expenditures...................      (7)      --        --           --             (7)
                                      ------     ----       ---          ---         ------
          Total costs incurred......  $  565     $112       $99          $13         $  789
                                      ======     ====       ===          ===         ======
2002 (Restated)(5)
  Property acquisition costs
     Proved properties..............  $   23     $  6       $--          $--         $   29
     Unproved properties............      12        7        --           --             19
  Exploration costs.................     197       70        --           --            267
  Development costs.................     569       80        --            2            651
                                      ------     ----       ---          ---         ------
          Total costs incurred......  $  801     $163       $--          $ 2         $  966
                                      ======     ====       ===          ===         ======
2001 (Restated)(5)
  Property acquisition costs
     Proved properties..............  $   87     $232       $--          $--         $  319
     Unproved properties............      33       16        --           --             49
  Exploration costs.................     182       22        --           --            204
  Development costs.................     954      102        --           --          1,056
                                      ------     ----       ---          ---         ------
          Total costs incurred......  $1,256     $372       $--          $--         $1,628
                                      ======     ====       ===          ===         ======
</Table>

---------------
(1) As of September 2004, we have sold our production operations in Canada.
(2) Includes international operations in Hungary and Indonesia. As of September
    2004, we have sold substantially all of our operations in Indonesia.
(3) Excludes $57 million that was paid by third parties under net profits
    interest agreements.
(4) In January 2003, we adopted SFAS No. 143, "Asset Retirement Obligations".
    Prior period presentation was not adjusted as amounts were adjusted through
    a one-time cumulative adjustment of approximately $6 million after tax,
    primarily in the U.S. which is further discussed in Note 2.
(5) We have reclassified some of our development costs to exploration costs as a
    result of the restatement of our natural gas and oil reserves.

     In our January 1, 2004 reserve report, the amounts estimated to be spent in
2004, 2005 and 2006 to develop our worldwide booked proved undeveloped reserves
are $248 million, $167 million and $321 million.

                                       113
<PAGE>

     Presented below is an analysis of the capitalized costs of natural gas and
oil properties by year of expenditure that are not being amortized as of
December 31, 2003, pending determination of proved reserves. Capitalized
interest of $9 million, $10 million, and $4 million for the years ended December
31, 2003, 2002 and 2001 is included in the presentation below (in millions):

<Table>
<Caption>
                                           CUMULATIVE    COSTS EXCLUDED FOR    CUMULATIVE
                                            BALANCE         YEARS ENDED         BALANCE
                                          DECEMBER 31,      DECEMBER 31,      DECEMBER 31,
                                          ------------   ------------------   ------------
                                              2003       2003   2002   2001       2000
                                          ------------   ----   ----   ----   ------------
<S>                                       <C>            <C>    <C>    <C>    <C>
Worldwide(1)
  Acquisition...........................      $212       $ 35   $38    $108       $31
  Exploration...........................       142         96    31       6         9
  Development...........................        35          3    --      30         2
                                              ----       ----   ---    ----       ---
                                              $389       $134   $69    $144       $42
                                              ====       ====   ===    ====       ===
</Table>

---------------

(1) Includes operations in the U.S., Canada, Brazil, Hungary and Indonesia. As
    of September 2004, we have sold our production operations in Canada and
    substantially all of our operations in Indonesia.

     Projects presently excluded from amortization are in various stages of
evaluation. The majority of these costs are expected to be included in the
amortization calculation in the years 2004 through 2007. For the U.S., the
amortization expense per Mcfe, including ceiling test charges, was $2.15, $2.99,
and $2.07 in 2003, 2002, and 2001. Excluding, ceiling test charges, amortization
expense would have been $1.90, $1.49 and $1.45 per Mcfe in 2003, 2002 and 2001.
For Canada, the total amortization expense per Mcfe, including ceiling test
charges, was $5.30, $4.81 and $16.15 in 2003, 2002 and 2001. Excluding ceiling
test charges, amortization expense would have been $1.71, $0.90 and $2.54 per
Mcfe in 2003, 2002 and 2001. In January 2003, we adopted SFAS No. 143,
Accounting for Asset Retirement Obligations. For further discussion, see Note 2.
Accretion expense per unit attributable to SFAS 143 was $0.08 in 2003.

     All of our proved properties, with the exception of the proved reserves in
Brazil, Hungary and Indonesia, are located in North America (U.S. and Canada).

     Net quantities of proved developed and undeveloped reserves of natural gas
and liquids, including condensate and crude oil, and changes in these reserves
at December 31, 2003 are presented below. Information in this table is based on
the reserve report dated January 1, 2004, prepared internally by us. Ryder Scott
Company and Huddleston & Co., Inc., independent petroleum engineering firms,
performed independent reserve estimates for 84 percent and 16 percent of our
properties, respectively. The total estimate of proved reserves prepared
independently by Ryder Scott Company and Huddleston & Co., Inc., was within five
percent of our internally prepared estimates for 2003 presented in the tables
below. The information at December 31, 2003, is consistent with estimates of
reserves filed with other federal agencies except for differences of less than
five percent resulting from actual production, acquisitions, property sales,
necessary reserve revisions and additions to reflect actual experience. Reserve
information as of and for the years ended December 31, 2001 and 2002 in the
following tables has been restated (for a further discussion, see Note 1).

<Table>
<Caption>
                                                                    NATURAL GAS (IN BCF)
                                                       ----------------------------------------------
                                                                                OTHER
                                                        U.S.    CANADA(1)   COUNTRIES(2)    WORLDWIDE
                                                       ------   ---------   -------------   ---------
<S>                                                    <C>      <C>         <C>             <C>
Net proved developed and undeveloped reserves(3)
  January 1, 2001 (Restated).........................   1,569       30            --          1,599
     Revisions of previous estimates(4)..............     (97)       4            --            (93)
     Extensions, discoveries and other...............     460       14            --            474
     Purchases of reserves in place..................      11       46            --             57
     Sales of reserves in place......................     (95)      --            --            (95)
     Production......................................    (373)     (13)           --           (386)
                                                       ------     ----           ---         ------
  December 31, 2001 (Restated).......................   1,475       81            --          1,556
     Revisions of previous estimates(4)..............    (164)       1            --           (163)
     Extensions, discoveries and other...............     279       54             5            338
</Table>

                                       114
<PAGE>

<Table>
<Caption>
                                                                    NATURAL GAS (IN BCF)
                                                       ----------------------------------------------
                                                                                OTHER
                                                        U.S.    CANADA(1)   COUNTRIES(2)    WORLDWIDE
                                                       ------   ---------   -------------   ---------
<S>                                                    <C>      <C>         <C>             <C>
     Purchases of reserves in place..................      --       --            --             --
     Sales of reserves in place......................    (504)     (23)           --           (527)
     Production......................................    (247)     (17)           --           (264)
                                                       ------     ----           ---         ------
  December 31, 2002 (Restated).......................     839       96             5            940
     Revisions of previous estimates(4)..............     (30)       2            --            (28)
     Extensions, discoveries and other...............      91       36            31            158
     Purchases of reserves in place..................       3       --            --              3
     Sales of reserves in place(5)...................    (136)     (22)           --           (158)
     Production......................................    (142)     (15)           (1)          (158)
                                                       ------     ----           ---         ------
  December 31, 2003..................................     625       97            35            757
                                                       ======     ====           ===         ======
Proved developed reserves
  December 31, 2001 (Restated).......................   1,028       70            --          1,098
  December 31, 2002 (Restated).......................     633       84            --            717
  December 31, 2003..................................     502       87             4            593
</Table>

---------------
(1) As of September 2004, we have sold our production operations in Canada.
(2) Includes international operations in Hungary and Indonesia. As of September
    2004, we have sold substantially all of our operations in Indonesia.
(3) Net proved reserves exclude royalties and interests owned by others
    (including net profits interest) and reflects contractual arrangements and
    royalty obligations in effect at the time of the estimate.
(4) Revisions reflect a number of items such as product price changes and
changes in product differentials.
(5) Sales of reserves in place include 11,416 MMcf of natural gas conveyed to
    third parties under net profits interest agreements.

                                       115
<PAGE>

<Table>
<Caption>
                                                                  LIQUIDS(1) (IN MBBLS)
                                                 --------------------------------------------------------
                                                                                    OTHER
                                                  U.S.     CANADA(2)   BRAZIL   COUNTRIES(3)    WORLDWIDE
                                                 -------   ---------   ------   -------------   ---------
<S>                                              <C>       <C>         <C>      <C>             <C>
Net proved developed and undeveloped
  reserves(4)
  January 1, 2001 (Restated)...................   47,080        410        --          --         47,490
     Revisions of previous estimates(5)........   (6,010)     1,309        --          --         (4,701)
     Extensions, discoveries and other.........   16,926        296        --          --         17,222
     Purchases of reserves in place............       16      3,857        --          --          3,873
     Sales of reserves in place................     (260)        (2)       --          --           (262)
     Production................................   (8,226)      (561)       --          --         (8,787)
                                                 -------    -------    ------       -----        -------
  December 31, 2001 (Restated).................   49,526      5,309        --          --         54,835
     Revisions of previous estimates(5)........   (1,946)      (103)       --          --         (2,049)
     Extensions, discoveries and other.........    7,114        288        --          --          7,402
     Purchases of reserves in place............       --         --        --          --             --
     Sales of reserves in place................  (11,283)    (2,062)       --          --        (13,345)
     Production................................   (6,928)    (1,053)       --          --         (7,981)
                                                 -------    -------    ------       -----        -------
  December 31, 2002 (Restated).................   36,483      2,379        --          --         38,862
     Revisions of previous estimates(5)........   (2,264)         1        --          --         (2,263)
     Extensions, discoveries and other.........    3,655      2,463    20,543       1,742         28,403
     Purchases of reserves in place............       43         --        --          --             43
     Sales of reserves in place(6).............   (1,019)    (1,548)       --          --         (2,567)
     Production................................   (5,978)      (309)       --          --         (6,287)
                                                 -------    -------    ------       -----        -------
  December 31, 2003............................   30,920      2,986    20,543       1,742         56,191
                                                 =======    =======    ======       =====        =======
Proved developed reserves
  December 31, 2001 (Restated).................   38,776      4,378        --          --         43,154
  December 31, 2002 (Restated).................   28,465      2,379        --          --         30,844
  December 31, 2003............................   23,136      1,708        --          --         24,844
</Table>

---------------

(1) Includes oil, condensate and natural gas liquids. Our year end 2003 natural
    gas liquids were 13,722 MBbls.
(2) As of September 2004, we sold our production operations in Canada.
(3) Includes international operations in Hungary and Indonesia. As of September
    2004, we have sold substantially all of our operations in Indonesia.
(4) Net proved reserves exclude royalties and interests owned by others
    (including net profits interest) and reflects contractual arrangements and
    royalty obligations in effect at the time of the estimate.
(5)Revisions reflect a number of items such as product price changes and changes
   in product differentials.
(6) Sales of reserves in place include 513 MBbl of liquids conveyed to third
    parties under net profits interest agreements.

     There are considerable uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures, including many factors beyond our control. The reserve
data represents only estimates. Reservoir engineering is a subjective process of
estimating underground accumulations of natural gas and oil that cannot be
measured in an exact manner. The accuracy of any reserve estimate is a function
of the quality of available data and of engineering and geological
interpretations and judgment. As a result, estimates of different engineers
often vary. Estimates are subject to revision based upon a number of factors,
including reservoir performance, prices, economic conditions and government
restrictions. In addition, results of drilling, testing and production
subsequent to the date of an estimate may justify revision of that estimate.
Reserve estimates are often different from the quantities of natural gas and oil
that are ultimately recovered. The meaningfulness of reserve estimates is highly
dependent on the accuracy of the assumptions on which they were based. In
general, the volume of production from natural gas and oil properties we own
declines as reserves are depleted. Except to the extent we conduct successful
exploration and development activities or acquire additional properties
containing proved reserves, or both, our proved reserves will decline as
reserves are produced. There have been no major discoveries or other events,
favorable or adverse, that may be considered to have caused a significant change
in the estimated proved reserves since December 31, 2003.

                                       116
<PAGE>

     In 2003, we entered into agreements to sell interests in a maximum of 42
wells to a subsidiary of Lehman Brothers and a wholly owned subsidiary of Nabors
Industries Ltd. As the wells are developed, these parties will pay 70 percent of
the drilling and completion costs in exchange for 70 percent of the net profits
of the wells sold. As each well is commenced, these parties receive an
overriding royalty interest in the form of a net profits interest in the well,
under which they are entitled to receive 70 percent of the aggregate net profits
of all wells until they have recovered 117.5 percent of their aggregate
investment. Upon this recovery, the net profits interest will convert to a
proportionately reduced 2 percent overriding royalty interest in the wells for
the remainder of the wells' productive life. We do not guarantee a return or
recovery of their costs or any return on their investment. All parties to the
agreement have the right to cease participation in the agreement at any time.
Upon ceasing participation in the agreement, they will continue to receive their
net profits interest on wells previously started, but will relinquish their
right to participate in any future wells. As of December 31, 2003, we have sold
interests in 13 wells with total proved reserves of 11,416 MMcf of natural gas
and 513 MBbl of liquids to them under these agreements. They have paid $57
million of drilling and development costs and were paid $7 million of the
revenues net of $1 million of expenses associated with these wells for the year
ended December 31, 2003. Subsequent to year end 2003, one party elected to cease
further investment in the program.

     Results of operations from producing activities by fiscal year were as
follows at December 31 (in millions):

<Table>
<Caption>
                                                                                         OTHER
                                                        U.S.     CANADA(1)   BRAZIL   COUNTRIES(2)   WORLDWIDE
                                                       ------    ---------   ------   ------------   ---------
<S>                                                    <C>       <C>         <C>      <C>            <C>
2003
Net Revenues
  Sales to external customers(3).....................  $  682      $  68      $ --       $   1        $  751
  Intersegment sales.................................     109         --        --          --           109
                                                       ------      -----      ----       -----        ------
        Total........................................     791         68        --           1           860
Production costs(4)..................................    (114)        (8)       --          --          (122)
Depreciation, depletion and amortization(5)..........    (346)       (29)       --          (1)         (376)
Ceiling test and other charges.......................     (34)       (74)       (5)         --          (113)
                                                       ------      -----      ----       -----        ------
                                                          297        (43)       (5)         --           249
Income tax expense...................................    (106)        15         2          --           (89)
                                                       ------      -----      ----       -----        ------
Results of operations from producing activities......  $  191      $ (28)     $ (3)      $  --        $  160
                                                       ======      =====      ====       =====        ======
2002
Net Revenues(Restated)(6)
  Sales to external customers(3).....................  $1,021      $  68      $ --       $  --        $1,089
  Intersegment sales.................................     106         --        --          --           106
                                                       ------      -----      ----       -----        ------
        Total........................................   1,127         68        --          --         1,195
Production costs(4)..................................    (162)       (18)       --          --          (180)
Depreciation, depletion and amortization.............    (446)       (21)       --          --          (467)
Ceiling test and other charges.......................    (417)       (95)       --          --          (512)
                                                       ------      -----      ----       -----        ------
                                                          102        (66)       --          --            36
Income tax benefit...................................     (35)        28        --          --            (7)
                                                       ------      -----      ----       -----        ------
Results of operations from producing activities......  $   67      $ (38)     $ --       $  --        $   29
                                                       ======      =====      ====       =====        ======
2001(Restated)(6)
Net Revenues
  Sales to external customers(3).....................  $1,697      $  46      $ --       $  --        $1,743
  Intersegment sales.................................     (35)        --        --          --           (35)
                                                       ------      -----      ----       -----        ------
        Total........................................   1,662         46        --          --         1,708
Production costs(4)..................................    (222)       (12)       --          --          (234)
Depreciation, depletion and amortization.............    (615)       (42)       --          --          (657)
Ceiling test and other charges.......................    (257)      (225)       --          --          (482)
                                                       ------      -----      ----       -----        ------
                                                          568       (233)       --          --           335
Income tax (expense) benefit.........................    (206)        98        --          --          (108)
                                                       ------      -----      ----       -----        ------
Results of operations from producing activities......  $  362      $(135)     $ --       $  --        $  227
                                                       ======      =====      ====       =====        ======
</Table>

---------------
(1) As of September 2004, we have sold our production operations in Canada.
(2) Includes international operations in Hungary.
(3) Sales to external customers include sales to third parties and other El Paso
    affiliates.
(4) Include lease operating costs and production related taxes (including ad
    valorem and severance taxes).
(5) In January 2003 we adopted SFAS No. 143, which is further discussed in Note
    2. Our 2003 depreciation, depletion and amortization includes accretion
    expense for SFAS No. 143 asset retirement obligations of $16 million
    primarily for the U.S.
(6) Amounts restated include depreciation, depletion and amortization expenses,
    ceiling test and other charges, income taxes and related subtotals and
    totals.

                                       117
<PAGE>

     The standardized measure of discounted future net cash flows relating to
proved natural gas and oil reserves follows at December 31 (in millions):

<Table>
<Caption>
                                                                                     OTHER
                                                    U.S.     CANADA(1)   BRAZIL   COUNTRIES(2)   WORLDWIDE
                                                   -------   ---------   ------   ------------   ---------
<S>                                                <C>       <C>         <C>      <C>            <C>
2003
Future cash inflows(3)...........................  $ 4,445    $  607     $ 588       $ 141        $ 5,781
Future production costs..........................     (967)     (124)      (65)        (44)        (1,200)
Future development costs.........................     (564)      (11)     (236)        (49)          (860)
Future income tax expenses.......................     (362)      (28)      (75)          3           (462)
                                                   -------    ------     -----       -----        -------
Future net cash flows............................    2,552       444       212          51          3,259
10% annual discount for estimated timing of cash
  flows..........................................     (735)     (154)     (128)        (21)        (1,038)
                                                   -------    ------     -----       -----        -------
Standardized measure of discounted future net
  cash flows.....................................  $ 1,817    $  290     $  84       $  30        $ 2,221
                                                   =======    ======     =====       =====        =======
Standardized measure of discounted future net
  cash flows, including effects of hedging
  activities.....................................  $ 1,729    $  290     $  84       $  30        $ 2,133
                                                   =======    ======     =====       =====        =======
2002(Restated)
Future cash inflows(3)...........................  $ 4,632    $  458     $  --       $  12        $ 5,102
Future production costs..........................   (1,071)     (111)       --          (2)        (1,184)
Future development costs.........................     (623)       (5)       --          (3)          (631)
Future income tax expenses.......................     (465)       (4)       --          --           (469)
                                                   -------    ------     -----       -----        -------
Future net cash flows............................    2,473       338        --           7          2,818
10% annual discount for estimated timing of cash
  flows..........................................     (738)     (117)       --          (1)          (856)
                                                   -------    ------     -----       -----        -------
Standardized measure of discounted future net
  cash flows.....................................  $ 1,735    $  221     $  --       $   6        $ 1,962
                                                   =======    ======     =====       =====        =======
Standardized measure of discontinued future net
  cash flows, including effects of hedging
  activities.....................................  $ 1,671    $  221     $  --       $   6        $ 1,898
                                                   =======    ======     =====       =====        =======
2001(Restated)
Future cash inflows(4)...........................  $ 4,261    $  301     $  --       $  --        $ 4,562
Future production costs..........................   (1,322)     (107)       --          --         (1,429)
Future development costs.........................     (778)      (17)       --          --           (795)
Future income tax expenses.......................       --        --        --          --             --
                                                   -------    ------     -----       -----        -------
Future net cash flows............................    2,161       177        --          --          2,338
10% annual discount for estimated timing of cash
  flows..........................................     (807)      (65)       --          --           (872)
                                                   -------    ------     -----       -----        -------
Standardized measure of discounted future net
  cash flows.....................................  $ 1,354    $  112     $  --       $  --        $ 1,466
                                                   =======    ======     =====       =====        =======
Standardized measure of discounted future net
  cash flows, including effects of hedging
  activities.....................................  $ 1,974    $  112     $  --       $  --        $ 2,086
                                                   =======    ======     =====       =====        =======
</Table>

---------------

(1) As of September 2004, we have sold our production operations in Canada.
(2) Includes international operations in Hungary and Indonesia. As of September
    2004, we have sold substantially all of our operations in Indonesia.
(3) Excludes $139 million and $111 million of future net cash outflows
    attributable to hedging activities during 2003 and 2002.
(4) Excludes $684 million of future net cash inflows attributable to hedging
    activities during 2001.

     For the calculations in the preceding table, estimated future cash inflows
from estimated future production of proved reserves were computed using year-end
commodity prices, adjusted for transportation and other charges. At December 31,
2003, the prices used were $30.90 per Bbl of oil, $5.76 per Mcf of gas and
$22.00 per Bbl of natural gas liquids. We may receive amounts different than the
standardized measure of discounted cash flow for a number of reasons, including
price changes and the effects of our hedging activities.

                                       118
<PAGE>

     We do not rely upon the standardized measure when making investment and
operating decisions. These decisions are based on various factors including
probable and proved reserves, different price and cost assumptions, actual
economic conditions, capital availability and corporate investment criteria.

     The following are the principal sources of change in the standardized
measure of discounted future net cash flows excluding the effects of hedging
activities (in millions):

<Table>
<Caption>
                                                                YEARS ENDED DECEMBER 31,(1)
                                                              --------------------------------
                                                                          2002         2001
                                                               2003    (RESTATED)   (RESTATED)
                                                              ------   ----------   ----------
<S>                                                           <C>      <C>          <C>
Sales and transfers of natural gas and oil produced net of
  production costs..........................................  $ (738)   $(1,013)     $(1,474)
Net changes in prices and production costs..................     666      1,980       (2,953)
Extensions, discoveries and improved recovery, less related
  costs.....................................................     556        680          501
Changes in estimated future development costs...............     (25)        46          123
Previously estimated development costs incurred during the
  period....................................................      50         91           26
Revisions of previous quantity estimates....................    (111)      (366)        (118)
Accretion of discount.......................................     218        147          475
Net change in income taxes..................................       8       (216)       1,026
Purchases of reserves in place..............................       7         --           84
Sales of reserves in place..................................    (417)    (1,195)         (92)
Changes in production rates, timing and other...............      45        342          139
                                                              ------    -------      -------
  Net change................................................  $  259    $   496      $(2,263)
                                                              ======    =======      =======
</Table>

---------------

(1) Includes operations in the U.S., Canada, Brazil, Hungary and Indonesia. As
    of September 2004, we have sold our production operations in Canada and
    substantially all of our operations in Indonesia.

                                       119
<PAGE>

            REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of
El Paso CGP Company:

     In our opinion, the consolidated financial statements listed in the Index
appearing under Item 15(a)(1) present fairly, in all material respects, the
consolidated financial position of El Paso CGP Company and its subsidiaries (the
"Company") at December 31, 2003 and 2002, and the consolidated results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2003 in conformity with accounting principles generally accepted in
the United States of America. In addition, in our opinion, the financial
statement schedule listed in the Index appearing under Item 15(a)(2) presents
fairly, in all material respects, the information set forth therein when read in
conjunction with the related consolidated financial statements. These financial
statements and the financial statement schedule are the responsibility of the
Company's management; our responsibility is to express an opinion on these
financial statements and the financial statement schedule based on our audits.
We conducted our audits of these statements in accordance with the standards of
the Public Company Accounting Oversight Board (United States). These standards
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

     As discussed in Note 1, the 2002 and 2001 consolidated financial statements
have been restated principally to reflect the financial statement impact of the
revision in the Company's estimates of its proved natural gas and oil reserves.
The Company's plans with regard to its current liquidity position are also
discussed in Note 1.

     As discussed in Notes 2 and 6, the Company adopted Statement of Financial
Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations
on January 1, 2003; SFAS No. 150, Accounting for Certain Financial Instruments
with Characteristics of Both Liabilities and Equity on July 1, 2003; SFAS No.
142, Goodwill and Other Intangible Assets and SFAS No. 144, Accounting for the
Impairment or Disposal of Long-Lived Assets on January 1, 2002; DIG Issue No.
C-16, Scope Exceptions: Applying the Normal Purchases and Sales Exception to
Contracts that Combine a Forward Contract and Purchased Option Contract on July
1, 2002; EITF Issue No. 02-3, Accounting for Contracts Involved in Energy
Trading and Risk Management Activities, Consensus 2 on October 1, 2002; and SFAS
No. 133, Accounting for Derivative Instruments and Hedging Activities on January
1, 2001.

/s/ PRICEWATERHOUSECOOPERS LLP

Houston, Texas
October 8, 2004

                                       120
<PAGE>

                                  SCHEDULE II

                      EL PASO CGP COMPANY AND SUBSIDIARIES
                       VALUATION AND QUALIFYING ACCOUNTS

                  YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001
                                 (IN MILLIONS)

<Table>
<Caption>
                                        BALANCE AT   CHARGED TO                                  BALANCE
                                        BEGINNING    COSTS AND                   CHARGED TO      AT END
             DESCRIPTION                OF PERIOD     EXPENSES    DEDUCTIONS   OTHER ACCOUNTS   OF PERIOD
             -----------                ----------   ----------   ----------   --------------   ---------
<S>                                     <C>          <C>          <C>          <C>              <C>
2003
  Allowance for doubtful accounts.....     $ 21         $ (1)        $ --           $ 17          $ 37
  Valuation allowance on deferred tax
     assets...........................       27          (26)(1)       --             --             1
  Legal reserves......................       49           (3)         (16)            (3)           27
  Environmental reserves..............       62           12          (10)            67(2)        131
  Provision for refund................        4           (3)          (1)            --            --
2002
  Allowance for doubtful accounts.....     $ 23         $  1         $ (7)(3)       $  4          $ 21
  Valuation allowance on deferred tax
     assets...........................       24            3           --             --            27
  Legal reserves......................       51           11          (26)(4)         13(5)         49
  Environmental reserves..............      163            9          (16)           (94)(6)        62
  Provision for refund................        5            7           (8)            --             4
2001
  Allowance for doubtful accounts.....     $ 10         $ 19         $ (6)(3)       $ --          $ 23
  Valuation allowance on deferred tax
     assets...........................        5           19(1)        --             --            24
  Legal reserves......................       23           27(7)        --              1            51
  Environmental reserves..............       13          151(3)        (1)            --           163
  Provision for refund................       --            5           --             --             5
</Table>

---------------
(1)Relates primarily to foreign ceiling test charges and revisions of future
   revenue estimates.
(2)Relates primarily to retained liabilities previously classified in our
   petroleum discontinued operations.
(3)Relates primarily to accounts written off.
(4)Relates primarily to payments for various litigation reserves.
(5)Relates to legal reserves previously imbedded in environmental reserves.
(6)In November 2002, we sold Coastal Mart, Inc. to an affiliate of El Paso which
   included environmental reserves of $95 million.
(7)These amounts primarily relate to additional liabilities recorded in
   connection with changes in our estimates of these liabilities. See Note 6 for
   a further discussion of this change.

                                       121
<PAGE>

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
        FINANCIAL DISCLOSURE.

     None.

ITEM 9A. CONTROLS AND PROCEDURES

     In February 2004, El Paso completed the annual review of its December 31,
2003 natural gas and oil reserve estimates, including our reserve estimates. As
a result of this review, El Paso reduced our proved natural gas and oil reserve
estimates by approximately 1.0 trillion cubic feet. In May 2004, El Paso
announced that, after further review and the completion of an independent
investigation into the factors that led to this reserve adjustment, it believed
that this reserve adjustment related to prior periods and the financial
statement amounts derived from these estimates would require a restatement of
prior period financial statements. The results of this independent investigation
indicated that certain employees used aggressive and, at times, unsupportable
methods to book proved reserves. In addition, the investigation concluded that
certain employees provided proved reserve estimates that they knew or should
have known were incorrect at the time they were reported. Consequently, we have
restated our historical financial information. The restatement impacted the
years from 1999 through 2002 and the first nine months of 2003. This
restatement, as well as specific information regarding its impact, is discussed
in Item 8, Financial Statements and Supplementary Data, Note 1.

     We have identified deficiencies in our internal controls that did not
prevent the overstatement of our natural gas and oil reserves. These
deficiencies, which we believe constituted a material weakness in our internal
controls over financial reporting, included a weak control environment
surrounding the booking of our natural gas and oil reserves in the Production
segment, inadequate controls over system access, inadequate documentation of
policies and procedures, and ineffective controls to monitor compliance with
existing policies and procedures.

     Our management, at the direction of El Paso's Board of Directors, is
actively working to improve the control environment and implement controls and
procedures that will ensure the integrity of our reserve booking process. As a
first step in that process, individuals have been added to El Paso's Board of
Directors and executive management team with extensive experience in the natural
gas and oil industry, and with experience in the preparation of natural gas and
oil reserve estimates. We have also implemented the following controls:

     - Formed an internal committee to provide oversight over the reserve
       estimation process, which is staffed with appropriate technical,
       financial reporting and legal expertise;

     - Continued to use an independent third-party engineering firm that is
       selected by and reports annually to the Audit Committee of El Paso's
       Board of Directors with a subsequent report by the Audit Committee to the
       full Board of Directors;

     - Formed a centralized reserve reporting function, staffed primarily with
       newly hired personnel that have extensive industry experience, that is
       separate from the operating divisions and reports directly to the
       president of Production and Non-regulated Operations;

     - Restricted security access to the reserve system to centralized reserve
       reporting staff; and

     - Revised our documentation of the procedures and controls for estimating
       proved reserves.

     In addition, we expect to have the following controls fully in place by
December 31, 2004:

     - Improved training regarding SEC guidelines for booking proved reserves;
       and

     - Enhanced internal audit reviews.

     During 2003, we initiated a project to ensure compliance with Section 404
of the Sarbanes-Oxley Act of 2002 (SOX), which will apply to us at December 31,
2005. This project entailed a detailed review and documentation of the processes
that impact the preparation of our financial statements, an assessment of the

                                       122
<PAGE>

risks that could adversely affect the accurate and timely preparation of those
financial statements, and the identification of controls in place to mitigate
the risks of untimely or inaccurate preparation of those financial statements.
Following the documentation of these processes, which was substantially
concluded by December 2003, we initiated an internal review or "walk-through" of
these financial processes by the financial management responsible for those
processes to evaluate the design effectiveness of the controls identified to
mitigate the risk of material misstatements occurring in our financial
statements. We have also initiated a detailed process to evaluate the operating
effectiveness of our controls over financial reporting. This process involves
testing the controls for effectiveness, including a review and inspection of the
documentary evidence supporting the operation of the controls on which we are
placing reliance.

     As a result of these efforts to ensure compliance with Section 404 of SOX,
we have become aware of deficiencies in our internal controls over financial
reporting in other areas of the company. The deficiencies include inadequate
change management and security access to our information systems, lack of
segregation of duties related to manual journal entry preparation and
procurement activities, lack of formal documentation of policies and procedures,
and untimely preparation and review of volume and account reconciliations.
Although we have not formally assessed the materiality of each deficiency
identified, we believe that the deficiencies in the aggregate constitute a
material weakness in our internal controls.

     We are actively remediating these deficiencies and have already implemented
action plans for the following:

     - Developing and implementing standard information system policies to
       govern change management and security access to our information systems
       across the company;

     - Modifying systems and procedures to ensure appropriate segregation of
       responsibilities for manual journal entry preparation;

     - Formalizing our account reconciliation policy and timely completing all
       material account reconciliations; and

     - Developing and implementing formal training to educate company personnel
       on management's responsibilities mandated by SOX Section 404, the
       components of the internal control framework on which we rely and the
       relationship to our company values including accountability, stewardship,
       integrity and excellence.

     We are in the process of implementing the following action plans and expect
to have them fully implemented by December 31, 2004:

     - Modifying systems and/or procedures to ensure appropriate segregation of
       responsibilities for procurement activities;

     - Implementing an account reconciliation tool to facilitate the monitoring
       of compliance with our account reconciliation policy;

     - Evaluating, formalizing and communicating required policies and
       procedures;

     - Implementing appropriate monitoring activities to ensure compliance with
       the company's policies and procedures; and

     - Reviewing the finance and accounting staffing.

     Many of the deficiencies in our internal controls that we have identified
are likely the result of significant changes the company has undergone during
the past five years as a result of major acquisitions and reorganizations. We
currently have company-wide efforts underway to formalize and improve our
internal controls and effectively remediate all of the deficiencies described
above. We have also performed additional analysis and procedures related to the
deficiencies identified and have concluded that the deficiencies have not
resulted in any material errors in these financial statements. As we continue
our SOX Section 404 compliance efforts, including the testing of the
effectiveness of our internal controls, we may identify additional deficiencies
in our system of internal controls over financial reporting that either
individually or in the

                                       123
<PAGE>

aggregate may represent a material weakness requiring additional remediation
efforts. We did not make any changes to our internal controls over financial
reporting during the quarter ended December 31, 2003, that have materially
affected, or are reasonably likely to materially affect, our internal controls
over financial reporting. However, as we discussed above, since December 31,
2003, we have made significant changes to our internal controls.

     We have communicated to El Paso's Audit Committee and to our external
auditors the deficiencies in our internal controls over financial reporting as
well as the remediation efforts that we have underway. Our management, with the
oversight of its Audit Committee, is committed to effectively remediating known
deficiencies as expeditiously as possible and continuing its efforts to comply
with Section 404 of the Sarbanes Oxley Act of 2002 by December 31, 2005.

     We undertook, in a separate evaluation under the supervision of our
principal executive and principal financial officers, and with the participation
of other members of our management, a review of our disclosure controls and
procedures. Disclosure controls and procedures include, without limitation,
controls and procedures designed to ensure that information required to be
disclosed by us in the reports that we file or submit under the Securities and
Exchange Act of 1934 is accumulated and communicated to our management,
including our principal executive and principal financial officers, or persons
performing similar functions, as appropriate to allow timely decisions regarding
required disclosure. As a result of the deficiencies and material weaknesses
identified above, we concluded that our disclosure controls and procedures were
ineffective as of December 31, 2003. To address the deficiencies and material
weaknesses described above, we significantly expanded our disclosure controls
and procedures to include additional analysis and other post-closing procedures
to ensure our disclosure controls and procedures were effective over the
preparation of these financial statements.

ITEM 9B. OTHER INFORMATION

     None.

                                    PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

     The following table sets forth certain information as of October 11, 2004,
regarding our executive officers and directors. Directors are elected annually
by our parent, and hold office until their successors are elected and duly
qualified. Each executive officer named in the following table has been elected
to serve until his successor is duly appointed or elected or until his earlier
removal or resignation from office. Information regarding our executive officers
may be found in Part I, Item I, Business, and is incorporated herein by
reference.

<Table>
<Caption>
            NAME              AGE                             POSITION
            ----              ---                             --------
<S>                           <C>   <C>
                                    Director; Chairman of the Board, President and Chief
Douglas L. Foshee...........  45    Executive Officer
                                    Director; Executive Vice President and Chief Financial
D. Dwight Scott.............  41    Officer
Robert W. Baker.............  48    Director; Executive Vice President and General Counsel
</Table>

     Douglas L. Foshee has served as our Chairman of the Board, President and
CEO since January 2004. Mr. Foshee has been President, Chief Executive Officer,
and a Director of El Paso since September 2003. Mr. Foshee became Executive Vice
President and Chief Operating Officer of Halliburton Company in 2003, having
joined that company in 2001 as Executive Vice President and Chief Financial
Officer. In December 2003, several subsidiaries of Halliburton, including DII
Industries and Kellogg Brown & Root, filed for bankruptcy protection whereby the
subsidiaries will jointly resolve their asbestos claims. Prior to that, Mr.
Foshee was President, Chief Executive Officer, and Chairman of the Board at
Nuevo Energy Company. From 1993 to 1997, Mr. Foshee served Torch Energy Advisors
Inc. in various capacities, including Chief Operating Officer and Chief
Executive Officer. He held various positions in finance and new business
ventures

                                       124
<PAGE>

with ARCO International Oil and Gas Company and spent seven years in commercial
banking, primarily as an energy lender.

     D. Dwight Scott has served as our Executive Vice President, Chief Financial
Officer and as a Director since January 2004. Mr. Scott has been Executive Vice
President and Chief Financial Officer of El Paso since October 2002. Mr. Scott
served as Senior Vice President of Finance and Planning for El Paso from July
2002 to September 2002. Mr. Scott was Executive Vice President of Power for El
Paso Merchant Energy from December 2001 to June 2002, and he served as Chief
Financial Officer of El Paso Global Networks from October 2000 to November 2001.
From January 1999 to October 2000, he served as a managing director in the
energy investment banking practice of Donaldson, Lufkin and Jenrette.

     Robert W. Baker has served as our Executive Vice President and General
Counsel since January 2004 and as a Director since April 2004. Mr. Baker has
been Executive Vice President and General Counsel of El Paso since January 2004.
From February 2003 to December 2003, he served as Executive Vice President of El
Paso and President of El Paso Merchant Energy. He was Senior Vice President and
Deputy General Counsel of El Paso from January 2002 to February 2003. Prior to
that time he held various positions in the legal department of Tenneco Energy
and El Paso since 1983.

     There are no family relationships among any of our executive officers or
directors, and, unless described herein, no arrangement or understanding exists
between any executive officer and any other person pursuant to which he was or
is to be selected as an officer or a director.

     We are a wholly-owned direct subsidiary of El Paso and rely on El Paso for
certain support services. As a result, we do not have a separate corporate audit
committee or audit committee financial expert. Also, we have not adopted a
separate code of ethics. However, our executives are subject to El Paso's Code
of Business Conduct which is available for your review at El Paso's website,
www.elpaso.com.

                                       125
<PAGE>

ITEM 11. EXECUTIVE COMPENSATION

     Compensation of Executive Officers. This table and narrative text discusses
the compensation paid in 2003, 2002 and 2001 by our affiliate to our Chief
Executive Officer and our two other most highly compensated executive officers
at December 31, 2003. We had no other executive officers during 2003. In
addition, as required by SEC rules, we have provided the compensation
information for Messrs. Kuehn and Wise who each served as our CEO at some point
during 2003. The compensation reflected for each individual was for their
services provided in all capacities to El Paso and its subsidiaries including
us. This table also identifies the principal capacity in which each of the
executives named in this Annual Report on Form 10-K served us at the end of
fiscal year 2003.

                           SUMMARY COMPENSATION TABLE

<Table>
<Caption>
                                                                                      LONG-TERM COMPENSATION
                                                                             ----------------------------------------
                                             ANNUAL COMPENSATION                     AWARDS               PAYOUTS
                                    --------------------------------------   -----------------------   --------------
                                                                             RESTRICTED   SECURITIES     LONG-TERM
                                                              OTHER ANNUAL     STOCK      UNDERLYING   INCENTIVE PLAN    ALL OTHER
                                      SALARY       BONUS      COMPENSATION     AWARDS      OPTIONS        PAYOUTS       COMPENSATION
NAME AND PRINCIPAL POSITION  YEAR     ($)(1)       ($)(2)        ($)(3)        ($)(4)        (#)           ($)(5)          ($)(6)
---------------------------  ----   ----------   ----------   ------------   ----------   ----------   --------------   ------------
<S>                          <C>    <C>          <C>          <C>            <C>          <C>          <C>              <C>
D. Dwight Scott............  2003   $  517,504   $  750,000           --     $       --          --              --     $   511,775
  Executive Vice             2002   $  387,504   $       --           --     $       --          --              --     $    71,108
  President and Chief        2001   $  252,091   $  360,039           --     $  179,961     137,000              --     $    59,628
  Financial Officer
Peggy A. Heeg..............  2003   $  467,512   $       --           --     $       --          --              --     $ 2,257,526
  Former Executive           2002   $  445,008   $       --           --     $       --          --              --     $   108,024
  Vice President and         2001   $  235,004   $  350,026           --     $  174,084     157,229              --     $   719,366
  General Counsel
Ronald L. Kuehn, Jr.(7)....  2003   $  568,462   $  600,000           --     $  247,500     125,000              --     $ 1,748,825
  Former Chief Executive
  Officer
William A. Wise(8).........  2003   $  297,918   $       --     $ 37,434     $       --          --      $2,166,750     $15,486,077
  Former Chief               2002   $1,430,004   $       --     $229,728     $       --          --              --     $   255,632
  Executive Officer          2001   $1,305,425   $3,432,000     $210,481     $1,715,997     768,250              --     $ 3,771,994
</Table>

---------------

(1) The amount reflected in the salary column for 2003 and 2002 for Ms. Heeg and
    Mr. Wise includes an amount for El Paso mandated reductions to fund certain
    charitable organizations.

(2) For fiscal year 2001, El Paso's incentive compensation plans required
    executives to receive a substantial part of their annual bonus in shares of
    restricted El Paso common stock. The amounts reflected in this column for
    2001 represent a combination of the market value of the restricted stock and
    cash at the time awarded under the applicable El Paso incentive compensation
    plan.

(3) The amount reflected for Mr. Wise in fiscal year 2003 includes, among other
    things, $18,750 for a perquisite and benefit allowance and $9,638 in value
    attributed to use of El Paso's aircraft. The amount reflected for Mr. Wise
    in fiscal year 2002 includes, among other things, $90,000 for a perquisite
    and benefit allowance and $65,509 in value attributed to use of El Paso's
    aircraft. The amount reflected for Mr. Wise in 2001 includes, among other
    things, $90,000 for a perquisite and benefit allowance and $62,692 in value
    attributed to use of El Paso's aircraft. Except as noted, the total value of
    the perquisites and other personal benefits received by the other executives
    named in this Annual Report on Form 10-K in fiscal years 2003, 2002 and 2001
    are not included in this column since they were below the Securities and
    Exchange Commission's reporting threshold.

(4) For fiscal year 2003, Mr. Kuehn received a grant of 50,000 shares of
    restricted El Paso common stock in connection with assumption of the interim
    CEO position of El Paso, the grant date value of which is reflected in this
    column. For fiscal year 2001, El Paso's incentive compensation plans
    provided for and encouraged participants to elect to take the cash portion
    of their annual bonus award in shares of restricted stock. The amounts
    reflected in this column for 2001 include the market value of restricted
    stock on the date of grant. The value of the shares of common stock issued
    has declined significantly since the date of grant. The total number of
    shares and value of restricted stock (including the amount in this column)
    held on December 31, 2003, is as follows:

                                       126
<PAGE>

            RESTRICTED EL PASO COMMON STOCK AS OF DECEMBER 31, 2003

<Table>
<Caption>
                                                                  TOTAL NUMBER
                                                                  OF RESTRICTED       VALUE OF
                                                                      STOCK       RESTRICTED STOCK
    NAME                                                               (#)              ($)
    ----                                                          -------------   ----------------
    <S>                                                           <C>             <C>
    D. Dwight Scott.............................................      58,444         $  478,656
    Peggy A. Heeg...............................................      43,089         $  352,899
    Ronald L. Kuehn, Jr.........................................          --         $       --
    William A. Wise.............................................          --         $       --
</Table>

    With the exception of Mr. Kuehn's grant, most of these shares of restricted
    stock are subject to a time-vesting schedule of four years from the date of
    grant (including the shares awarded as part of the annual bonus in 2001
    described above) and other shares of restricted stock which are subject to
    both time-vesting and performance-vesting. With respect to performance
    vesting, if the required El Paso performance targets are not met within a
    four-year time period, all unvested shares are forfeited. Any dividends
    awarded on the restricted stock are paid directly to the holder of the El
    Paso common stock. These total values can be realized only if the executives
    named in this Annual Report on Form 10-K remain employees of El Paso for the
    required period of years and, with respect to performance vesting, the
    performance goals regarding stockholder value are reached.

(5) For fiscal year 2003, the amount reflected in this column is the value of
    shares of restricted El Paso common stock on the date they vested. These
    shares had been reported in a long-term incentive table in El Paso's proxy
    statement for the year in which those shares of restricted stock were
    originally granted, along with the necessary performance measures necessary
    for their vesting. No long-term incentive payouts were made in fiscal years
    2002 and 2001.

(6) The compensation reflected in this column for fiscal year 2003 includes El
    Paso's contributions to the El Paso Retirement Savings Plan and supplemental
    company match for the El Paso Retirement Savings Plan under the El Paso
    Supplemental Benefits Plan, as follows:

             EL PASO'S CONTRIBUTIONS TO THE RETIREMENT SAVINGS PLAN
                    AND SUPPLEMENTAL COMPANY MATCH UNDER THE
                SUPPLEMENTAL BENEFITS PLAN FOR FISCAL YEAR 2003

<Table>
<Caption>
                                                                   RETIREMENT    SUPPLEMENTAL
                                                                  SAVINGS PLAN   BENEFITS PLAN
    NAME                                                              ($)             ($)
    ----                                                          ------------   -------------
    <S>                                                           <C>            <C>
    D. Dwight Scott.............................................     $3,750         $8,025
    Peggy A. Heeg...............................................     $3,059         $7,425
    Ronald L. Kuehn, Jr.........................................     $   --         $   --
    William A. Wise.............................................     $9,000         $2,850
</Table>

    In addition, for fiscal year 2003 for Mr. Scott and Ms. Heeg, the amount in
    this column includes the value of special retention payments in the amount
    $500,000 and $525,000, respectively. In addition, for fiscal year 2003 for
    Ms. Heeg, the amount in this column includes $1,722,042 in severance paid
    under El Paso's Severance Pay Plan. In addition, for fiscal year 2003 for
    Mr. Kuehn, the amount in this column includes $881,588 for the value of the
    split-dollar life insurance policy transferred to him in January 2003,
    $619,723 for the tax gross-up associated with the transfer of the
    split-dollar life insurance policy, $100,000 in severance attributed to him
    ceasing as interim CEO of El Paso and non-employee director fees received
    for serving on El Paso's Board of Directors during 2003. In addition, for
    fiscal year 2003 for Mr. Wise, the amount in this column includes
    $15,474,227 ($15,326,532 of which includes his supplemental pension benefit
    earned during his employment) paid in connection with his termination.

(7) Mr. Kuehn served as CEO of El Paso from March 13, 2003 to September 1, 2003.

(8) Mr. Wise ceased to be CEO of El Paso on March 12, 2003. See Item 11,
    Executive Compensation for a description of Mr. Wise's employment agreement
    with El Paso and the severance benefits he received pursuant to his
    employment agreement.

EL PASO CORPORATION STOCK OPTION GRANTS

     This table sets forth the number of El Paso stock options granted at fair
market value to the executives named in this Annual Report on Form 10-K during
the fiscal year 2003. In satisfaction of applicable SEC regulations, the table
further sets forth the potential realizable value of such stock options in the
year 2013 (the expiration date of the stock options) at an assumed annualized
rate of stock price appreciation of 5% and 10% over the full ten-year term of
the stock options. As the table indicates for the grant made on September 2,
2003, annualized stock price appreciation of 5% and 10% would result in stock
prices in the year 2013 of approximately $11.96 and $19.05, respectively.
Further as the table indicates for the grant made on March 21, 2003, annualized
stock price appreciation of 5% and 10% would result in stock prices in the year
2013 of approximately $10.64 and $16.95, respectively. The amounts shown in the
table as potential realizable values for all stockholders' stock (approximately
$2.9 billion and $7.4 billion for the September grant and

                                       127
<PAGE>

approximately $2.6 billion and $6.6 billion for the March grant), represent the
corresponding increases in the market value of 633,912,031 shares of El Paso
common stock outstanding as of December 31, 2003. No gain to the executive named
in this Annual Report on Form 10-K is possible without an increase in stock
price, which would benefit all stockholders. Actual gains, if any, on stock
option exercises and El Paso common stock holdings are dependent on the future
performance of El Paso common stock and overall stock market conditions. There
can be no assurances that the potential realizable values shown in this table
will be achieved.

                         EL PASO OPTION GRANTS IN 2003

<Table>
<Caption>
                                                                                                POTENTIAL REALIZABLE VALUE AT
                                                                                                ASSUMED ANNUAL RATES OF STOCK
                                                      INDIVIDUAL GRANTS(1)                   PRICE APPRECIATION FOR OPTION TERM
                                        -------------------------------------------------   -------------------------------------
                                                      % OF TOTAL                            IF STOCK PRICE AT   IF STOCK PRICE AT
                                         NUMBER OF     OPTIONS                                $11.96423 AND       $19.05104 AND
                                        SECURITIES     GRANTED                                $10.64483 IN        $16.95011 IN
                                        UNDERLYING      TO ALL     EXERCISE                       2013                2013
                                          OPTIONS     EMPLOYEES      PRICE     EXPIRATION   -----------------   -----------------
NAME                                    GRANTED (#)    IN 2003     ($/SHARE)      DATE           5% ($)              10% ($)
----                                    -----------   ----------   ---------   ----------   -----------------   -----------------
<S>                                     <C>           <C>          <C>         <C>          <C>                 <C>
POTENTIAL VALUE OF ALL EL PASO COMMON
  STOCK OUTSTANDING ON
  DECEMBER 31, 2003
  SEPTEMBER 2, 2003 GRANT.............         N/A        N/A           N/A          N/A     $2,928,186,126      $7,420,598,558
  MARCH 21, 2003 GRANT................         N/A        N/A           N/A          N/A     $2,605,268,391      $6,602,261,617
Ronald L. Kuehn, Jr. .................     125,000      11.10%     $6.53500    3/21/2003     $      513,728      $    1,301,888
</Table>

---------------

(1) The El Paso stock options granted in 2003 to Mr. Kuehn vested in September
    2003 when he ceased to be El Paso's interim CEO. No stock options were
    granted to any other of the named executives. There were no stock
    appreciation rights granted in 2003. Any unvested stock options become fully
    exercisable in the event of a "change in control" of El Paso. See Item 11,
    Executive Compensation of this Annual Report on Form 10-K for a description
    of El Paso's 2001 Omnibus Incentive Compensation Plan and the definition of
    the term "change in control." Under the terms of El Paso's 2001 Omnibus
    Incentive Compensation Plan, El Paso's Compensation Committee may, in its
    sole discretion and at any time, change the vesting of the stock options.
    Certain non-qualified stock options may be transferred to immediate family
    members, directly or indirectly or by means of a trust, corporate entity or
    partnership. Further, stock options are subject to forfeiture and/or time
    limitations on exercise in the event of termination of employment.

EL PASO CORPORATION OPTION EXERCISES AND YEAR-END VALUE TABLE

     This table sets forth information concerning El Paso stock option exercises
and the fiscal year-end values of the unexercised stock options, provided on an
aggregate basis, for each of the executives named in this Annual Report on Form
10-K.

                      AGGREGATED OPTION EXERCISES IN 2003
                       AND FISCAL YEAR-END OPTION VALUES

<Table>
<Caption>
                                                           NUMBER OF SECURITIES            VALUE OF UNEXERCISED
                               SHARES                 UNDERLYING UNEXERCISED OPTIONS      IN-THE-MONEY OPTIONS AT
                              ACQUIRED      VALUE         AT FISCAL YEAR-END (#)          FISCAL YEAR-END ($)(2)
                             ON EXERCISE   REALIZED   -------------------------------   ---------------------------
NAME                           (#)(1)       ($)(1)    EXERCISABLE      UNEXERCISABLE    EXERCISABLE   UNEXERCISABLE
----                         -----------   --------   ------------     --------------   -----------   -------------
<S>                          <C>           <C>        <C>              <C>              <C>           <C>
D. Dwight Scott............         --     $     --      115,247            28,247       $     --         $ --
Peggy A. Heeg..............     11,333     $ 81,541      166,730                --       $     --         $ --
Ronald L. Kuehn, Jr. ......         --     $     --      614,300                --       $208,750         $ --
William A. Wise............    100,000     $719,500    1,787,917(3)             --       $     --         $ --
</Table>

---------------

(1) The amounts in these columns represent the number of El Paso shares and the
    value realized upon conversion of El Paso stock options into shares of El
    Paso's common stock that occurred during 2003 based upon the achievement of
    certain El Paso performance targets established when they were originally
    granted in 1999.

(2) The figures presented in these columns have been calculated based upon the
    difference between $8.205, the fair market value of El Paso's common stock
    on December 31, 2003, for each in-the-money stock option, and its exercise
    price. No cash is realized until

                                       128
<PAGE>

    the shares received upon exercise of an option are sold. No executives named
    in this Annual Report on Form 10-K had stock appreciation rights that were
    outstanding on December 31, 2003.

(3) Includes 98,000 stock options held by the William & Marie Wise Family Ltd.
    Partnership.

                        EL PASO CORPORATION PENSION PLAN

     Effective January 1, 1997, El Paso amended its pension plan to provide
pension benefits under a cash balance plan formula that defines participant
benefits in terms of a hypothetical account balance. Prior to adopting a cash
balance plan, El Paso provided pension benefits under a plan (the "Prior Plan")
that defined monthly benefits based on final average earnings and years of
service. Under the cash balance plan, an initial account balance was established
for each El Paso employee who was a participant in the Prior Plan on December
31, 1996. The initial account balance was equal to the present value of Prior
Plan benefits as of December 31, 1996.

     At the end of each calendar quarter, participant account balances are
increased by an interest credit based on 5-Year Treasury bond yields, subject to
a minimum interest credit of 4% per year, plus a pay credit equal to a
percentage of salary and bonus. The pay credit percentage is based on the sum of
age plus service at the end of the prior calendar year according to the
following schedule:

<Table>
<Caption>
AGE PLUS SERVICE                                               PAY CREDIT PERCENTAGE
----------------                                               ---------------------
<S>                                                            <C>
Less than 35................................................             4%
35 to 49....................................................             5%
50 to 64....................................................             6%
65 and over.................................................             7%
</Table>

     Under El Paso's pension plan and applicable Internal Revenue Code
provisions, compensation in excess of $200,000 cannot be taken into account and
the maximum payable benefit in 2003 was $160,000. Any excess benefits otherwise
accruing under El Paso's pension plan are payable under El Paso's Supplemental
Benefits Plan. Participants will receive benefits in the form of a lump sum
payment under the Supplemental Benefits Plans unless a valid irrevocable
election was made to receive payment in a form other than lump sum prior to June
1, 2004.

     Participants with an initial account balance on January 1, 1997 are
provided minimum benefits equal to the Prior Plan benefit accrued as of the end
of 2001. Upon retirement, certain participants (including Mr. Wise) are provided
pension benefits that equal the greater of the cash balance formula benefit or
the Prior Plan benefit. For Mr. Wise, the Prior Plan benefit reflects accruals
through the end of 2001 and is computed as follows: for each year of credited
service up to a total of 30 years, 1.1% of the first $26,800, plus 1.6% of the
excess over $26,800, of the participant's average annual earnings during his
five years of highest earnings.

     Credited service as of December 31, 2001, for Mr. Wise is shown in the
table below. Amounts reported under Salary and Bonus for each executive named in
the Summary Compensation Table approximate earnings as defined under the pension
plan.

     Estimated annual benefits payable from the pension plan and El Paso
Supplemental Benefits Plan upon retirement at the normal retirement age (age 65)
for each named executive is reflected below (based on assumptions that each
named executive receives base salary shown in the Summary Compensation Table
with no pay increases, receives 50% of target annual bonuses beginning with
bonuses earned for fiscal year 2004, and cash balances are credited with
interest at a rate of 4% per annum):

<Table>
<Caption>
                                                                                        ESTIMATED
                                                               PAY CREDIT PERCENTAGE     ANNUAL
NAMED EXECUTIVE                          CREDITED SERVICE(1)        DURING 2003        BENEFITS(2)
---------------                          -------------------   ---------------------   -----------
<S>                                      <C>                   <C>                     <C>
Dwight Scott...........................          N/A                     5%             $198,568
Peggy Heeg(3)..........................          N/A                     6%             $ 33,865
Ronald Kuehn(4)........................          N/A                     7%             $ 78,093
William A. Wise(5).....................           30                     7%             $881,725
</Table>

                                       129
<PAGE>

---------------

(1) For Mr. Wise, credited service shown is as of December 31, 2001.

(2) For Mr. Wise, the amount reflected has been reduced as a result of his
    participation in the El Paso Alternative Benefits Program, as described in
    this Item 11 Executive Compensation. The Prior Plan minimum benefit for Mr.
    Wise is greater than his projected cash balance benefit at age 65.

(3) The amount reflected for Ms. Heeg is her vested pension benefit amount under
    both the El Paso Supplemental Benefits Plan and the tax-qualified pension
    plan as of her termination date of December 31, 2003, payable commencing at
    age 65.

(4) The amount reflected for Mr. Kuehn is his vested pension benefit amount
    under both the El Paso Supplemental Benefits Plan and the tax-qualified
    pension plan as of his termination date of September 2, 2003, payable
    commencing October 1, 2003 (at age 68). Mr. Kuehn has elected to receive his
    El Paso Supplemental Benefits Plan benefit in a lump sum of $79,211, minus
    amounts withheld for taxes. Mr. Kuehn has also elected to receive his
    benefit under the tax-qualified pension plan in a lump sum of $15,834.
    Additionally, due to Mr. Kuehn's previous employment with Sonat, he is also
    receiving an annual benefit (75% joint and survivor form of payment) under
    the tax-qualified pension plan equal to $69,309.

(5) The amount reflected for Mr. Wise is his vested pension benefit amount under
    both the El Paso Supplemental Benefits Plan and the tax-qualified pension
    plan as of his termination date of March 12, 2003, payable commencing at age
    65. Mr. Wise has elected to receive his El Paso Supplemental Benefits Plan
    benefit in a lump sum of $15,326,532, minus amounts withheld for taxes. Mr.
    Wise elected to receive a single life annuity benefit under the
    tax-qualified pension plan equal to $97,520 annually.

                EMPLOYMENT CONTRACTS, TERMINATION OF EMPLOYMENT
                       AND CHANGE IN CONTROL ARRANGEMENTS

EMPLOYMENT AGREEMENTS

  FORMER EMPLOYEES

     As part of the merger with Sonat, El Paso entered into a termination and
consulting agreement with Ronald L. Kuehn, Jr., dated October 25, 1999. Under
this agreement, Mr. Kuehn served as the non-executive Chairman of El Paso's
Board of Directors through December 31, 2000, and received a fee of $20,833 per
month from October 25, 1999 through December 31, 2000. In addition, Mr. Kuehn
received the perquisites that were available to him prior to the merger with
Sonat pursuant to this agreement, as well as non-cash compensation available to
other non-employee directors. Starting on October 25, 1999, and for the
remainder of his life, Mr. Kuehn will receive certain ancillary benefits made
available to him prior to the merger with Sonat, including the provision of
office space and related services, and payment of life insurance premiums
sufficient to provide a death benefit equal to four times his base pay as in
effect immediately prior to October 25, 1999. Mr. Kuehn and his eligible
dependents will also receive retiree medical coverage. El Paso maintained a
collateral assignment split-dollar life insurance policy to provide for the
death benefit for Mr. Kuehn to satisfy its obligation to provide the life
insurance referenced above. In January 2003, El Paso released the collateral
assignment on the policy. El Paso recovered $1,116,303 from the policy's cash
surrender value for premiums paid by El Paso and its predecessors for Mr. Kuehn
under the policy and gave up the right to recoup $881,588, which was left in the
policy to provide coverage under the policy until age 95. The release of the
collateral assignment and the right to recoup $881,588 was treated as a transfer
of property to Mr. Kuehn subject to ordinary income tax. El Paso paid Mr. Kuehn
$619,723 to satisfy the tax liabilities related to the transfer of the policy.
In March 2003, Mr. Kuehn, in an interim capacity, replaced Mr. Wise as Chief
Executive Officer of El Paso. At that time, El Paso entered into an employment
agreement with Mr. Kuehn effective upon his appointment as interim Chief
Executive Officer of El Paso. Mr. Kuehn has also served as Chairman of the Board
of El Paso since March 2003. Under his employment agreement, Mr. Kuehn received
a monthly salary of $100,000 and was eligible to earn a target bonus amount
equal to 100% of his annual salary based on El Paso's and his performance as
determined by El Paso's Compensation Committee. Pursuant to his employment
agreement, on the date Mr. Foshee began as the permanent Chief Executive Officer
of El Paso, Mr. Kuehn received a pro-rated portion of his target bonus based on
the number of months he served as the interim Chief Executive Officer in the
amount of $600,000 and a termination payment in the amount of $100,000 for the
time he served as interim Chief Executive Officer. Mr. Kuehn's employment
agreement also provided for an award of 125,000 nonqualified stock options to
purchase shares of El Paso's common stock and 50,000 shares of restricted stock
of El Paso under the El Paso 2001 Omnibus Incentive

                                       130
<PAGE>

Compensation Plan. His stock options vested and all restrictions on his
restricted stock lapsed on the date Mr. Foshee began as the permanent Chief
Executive Officer of El Paso.

     Effective as of March 12, 2003, Mr. Kuehn replaced William A. Wise as Chief
Executive Officer and Chairman of the Board of Directors of El Paso pending
selection of a permanent Chief Executive Officer. Under the terms of his
pre-existing employment agreement with El Paso, Mr. Wise received the severance
benefits set for in his pre-existing employment agreement for the remaining
three-year term of his agreement consisting of his annual salary of $1,430,004,
an annual bonus in the amount of $1,716,004, service credit and age credit for
pension benefits and continued medical, dental and vision insurance. Effective
in May 2004, payment to Mr. Wise of his annual salary was suspended. In May
2004, Mr. Wise initiated an arbitration in connection with his employment
agreement. Mr. Wise asserts that he is entitled to additional perquisites under
the terms of his pre-existing employment agreement. Mr. Wise is not entitled to
receive benefits under his employment agreement that otherwise would arise in
connection with any future change in control of El Paso. Any salary, bonus, or
benefits received by Mr. Wise in connection with any full-time employment during
the remaining three-year term will reduce the salary, bonus, or benefits payable
to Mr. Wise under the terms of his agreement. In March 2003, El Paso transferred
ownership of Mr. Wise's company-owned automobile to Mr. Wise and agreed to
purchase his Houston residence, if timely requested to do so, at the greater of
its appraised value or the amount of Mr. Wise's investment. In 1997, El Paso
loaned Mr. Wise $1,564,000 with interest at 6.8% for the purchase of his Houston
residence. On March 19, 2003, Mr. Wise repaid this loan in full with accrued
interest, consisting of $1,564,000 in principal and $617,436 in interest. In
2001, El Paso loaned Mr. Wise $7,332,195 with interest at 4.99% to fund Mr.
Wise's exercise of options to purchase El Paso common stock. This outstanding
loan obligation became payable by Mr. Wise in full upon the cessation of his
employment. On April 23, 2003, Mr. Wise repaid this loan in full with accrued
interest, consisting of $7,332,195 in principal and $594,549 in interest. In
addition, Mr. Wise held 1,887,917 vested El Paso stock options. These options
are exercisable by Mr. Wise through March 12, 2006, unless they expire earlier
in accordance with their terms. Any portion of these options not exercised by
March 12, 2006 or any earlier applicable expiration date will be forfeited on
that date. Of these 1,887,917 stock options, 100,000 were converted
automatically into shares of El Paso common stock on October 25, 2003, with the
value per option equal to the fair market value of El Paso common stock on that
date. Mr. Wise forfeited 258,333 unvested stock options when he ceased to be an
employee of El Paso on March 12, 2003. In addition, 491,639 shares of restricted
El Paso common stock held by Mr. Wise as of March 12, 2003 became vested as of
that date, and 139,609 shares of restricted stock were forfeited as of that
date. Mr. Wise also became vested in 33,281 performance units, the performance
cycle for which ended in June 2003, without value, and he forfeited 2,219
unvested performance units.

BENEFIT PLANS

     El Paso Severance Pay Plan.  The El Paso Severance Pay Plan is a
broad-based employee plan providing severance benefits following a "qualifying
termination" for all salaried employees of El Paso and certain of its
subsidiaries. The plan also includes an executive supplement, which provides
enhanced severance benefits for certain executive officers of El Paso and
certain of its subsidiaries, including Mr. Foshee, Mr. Scott, and Mr. Baker. The
enhanced severance benefits available under the supplement include an amount
equal to two times the sum of the officer's annual salary, including annual
target bonus amounts as specified in the plan. A qualifying termination includes
an involuntary termination of the officer as a result of the elimination of the
officer's position or a reduction in force and a termination for "good reason"
(as defined under the plan). In the event the El Paso Severance Pay Plan is
terminated, the executive supplement will continue as a separate plan unless the
action terminating the El Paso Severance Pay Plan explicitly terminates the
supplement. The executive supplement of the El Paso Severance Pay Plan
terminates on January 1, 2005, unless extended. In the event of a "change in
control" (as defined in the El Paso Key Executive Severance Protection Plan) of
El Paso, participants whose termination of employment entitles them to severance
pay under the executive supplement and the El Paso Key Executive Severance
Protection Plan will receive severance pay under the El Paso Key Executive
Severance Protection Plan, rather than under the executive supplement.

                                       131
<PAGE>

     El Paso 2004 Key Executive Severance Protection Plan.  El Paso periodically
reviews its benefits plans and engages Deloitte Consulting to make
recommendations regarding its plans. Deloitte recommended that El Paso adopt a
new executive severance plan that more closely aligns with current market
arrangements than El Paso's Key Executive Severance Protection Plan and Employee
Severance Protection Plan (as described below). In light of Deloitte's
recommendation, El Paso adopted this plan in March 2004. This plan provides
severance benefits following a "change in control" of El Paso for executives of
El Paso and certain of its subsidiaries, as designated by El Paso's Board or
Compensation Committee, including Mr. Foshee, Mr. Scott, and Mr. Baker. This
plan is intended to replace the El Paso Key Executive Severance Protection Plan
and Employee Severance Protection Plan, and participants are required to waive
their participation under those plans (if applicable) as a condition to becoming
participants in this plan. The benefits of the plan include: (1) a cash
severance payment in an amount equal to three times the annual salary and target
bonus for the CEO of El Paso, two times the annual salary and target bonus for
executive vice presidents and senior vice presidents, including Mr. Scott, and
one times the annual salary and target bonus for vice presidents; (2) a prorated
portion of the executive's target bonus for the year in which the termination of
employment occurs; (3) continuation of life and health insurance following
termination for a period of 36 months for the CEO of El Paso, 24 months for
executive vice presidents and senior vice presidents of El Paso, including Mr.
Scott and Mr. Baker, and 12 months for vice presidents of El Paso; (4) a
gross-up payment for any federal excise tax imposed on an executive in
connection with any payment or distribution made by El Paso or any of its
affiliates under the plan or otherwise; provided that in the event a reduction
in payments in respect of the executive of 10% or less would cause no excise tax
to be payable in respect of that executive, then the executive will not be
entitled to a gross-up payment and payments to the executive shall be reduced to
the extent necessary so that the payments shall not be subject to the excise
tax; and (5) payment of legal fees and expenses incurred by the executive to
enforce any rights or benefits under the plan. Benefits are payable for any
termination of employment of an executive in the plan within two years following
the date of a change in control of El Paso, except where termination is by
reason of death, disability, for "cause" (as defined in the plan) or instituted
by the executive other than for "good reason" (as defined in the plan). Benefits
are also payable under the plan for terminations of employment prior to a change
in control of El Paso that arise in connection with, or in anticipation of, a
change in control. Benefits are not payable for any termination of employment
following a change in control of El Paso if (i) the termination occurs in
connection with the sale, divestiture or other disposition of designated
subsidiaries of El Paso, (ii) the purchaser or entity subject to the transaction
agrees to provide severance benefits at least equal to the benefits available
under the plan, and (iii) the executive is offered, or accepts, employment with
the purchaser or entity subject to the transaction. A change in control of El
Paso generally occurs if: (i) any person or entity becomes the beneficial owner
of more than 20% of El Paso's common stock; (ii) a majority of the current
members of the Board of Directors of El Paso or their approved successors cease
to be directors of El Paso (or, in the event of a merger, the ultimate parent
following the merger); or (iii) a merger, consolidation, or reorganization of El
Paso, a complete liquidation or dissolution of El Paso, or the sale or
disposition of all or substantially all of El Paso's and its subsidiaries'
assets (other than a transaction in which the same stockholders of El Paso
before the transaction own 50% of the outstanding common stock after the
transaction is complete). This plan generally may be amended or terminated at
any time prior to a change in control, provided that any amendment or
termination that would adversely affect the benefits or protections of any
executive under the plan shall be null and void as it relates to that executive
if a change in control occurs within one year of the amendment or termination.
In addition, any amendment or termination of the plan in connection with, or in
anticipation of, a change in control which actually occurs shall be null and
void. From and after a change in control, the plan may not be amended in any
manner that would adversely affect the benefits or protections provided to any
executive under the plan.

     El Paso Key Executive Severance Protection Plan.  This plan, initially
adopted in 1992, provides severance benefits following a "change in control" of
El Paso for certain officers of El Paso and certain of its subsidiaries. The
benefits of the plan include: (1) an amount equal to three times the
participant's annual salary, including maximum bonus amounts as specified in the
plan; (2) continuation of life and health insurance for an 18-month period
following termination; (3) a supplemental pension payment calculated by adding
three years of additional credited pension service; (4) certain additional
payments to the terminated employee to cover excise taxes if the payments made
under the plan are subject to excise taxes on golden

                                       132
<PAGE>

parachute payments; and (5) payment of legal fees and expenses incurred by the
employee to enforce any rights or benefits under the plan. Benefits are payable
for any termination of employment for a participant in the plan within two years
of the date of a change in control of El Paso, except where termination is by
reason of death, disability, for cause or instituted by the employee for other
than "good reason" (as defined in the plan). A change in control of El Paso
occurs if: (i) any person or entity becomes the beneficial owner of 20% or more
of El Paso's common stock; (ii) any person or entity (other than El Paso)
purchases the common stock by way of a tender or exchange offer; (iii) El Paso
stockholders approve a merger or consolidation, sale or disposition or a plan of
liquidation or dissolution of all or substantially all of El Paso's assets; or
(iv) if over a two year period a majority of the members of the El Paso Board of
Directors at the beginning of the period cease to be directors. A change in
control has not occurred if El Paso is involved in a merger, consolidation or
sale of assets in which the same stockholders of El Paso before the transaction
own 80% of the outstanding common stock after the transaction is complete. This
plan generally may be amended or terminated at any time, provided that no
amendment or termination may impair participants' rights under the plan or be
made following the occurrence of a change in control. This plan is closed to new
participants, unless the El Paso Board of Directors determines otherwise.

     El Paso Supplemental Benefits Plan.  This plan provides for certain
benefits to officers and key management employees of El Paso and its
subsidiaries. The benefits include: (1) a credit equal to the amount that a
participant did not receive under El Paso's Pension Plan because the Pension
Plan does not consider deferred compensation (whether in deferred cash or
deferred restricted common stock) for purposes of calculating benefits and
eligible compensation is subject to certain Internal Revenue Code limitations;
and (2) a credit equal to the amount of El Paso's matching contribution to El
Paso's Retirement Savings Plan that cannot be made because of a participant's
deferred compensation and Internal Revenue Code limitations. The plan may not be
terminated so long as the El Paso Pension Plan and/or El Paso Retirement Savings
Plan remain in effect. The management committee of this plan designates who may
participate and also administers the plan. Benefits under El Paso's Supplemental
Benefits Plan are paid upon termination of employment in a lump-sum payment. In
the event of a change in control (as defined under the El Paso Key Executive
Severance Protection Plan) of El Paso, the supplemental pension benefits become
fully vested and nonforfeitable.

     El Paso Senior Executive Survivor Benefits Plan.  This plan provides
certain senior executives (including each of the named executives in this Annual
Report on Form 10-K, except for Ms. Heeg and Messrs. Wise and Kuehn who are no
longer employees) of El Paso and its subsidiaries who are designated by the plan
administrator with survivor benefit coverage in lieu of the coverage provided
generally for employees under El Paso's group life insurance plan. The amount of
benefits provided, on an after-tax basis, is two and one-half times the
executive's annual salary. Benefits are payable in installments over 30 months
beginning within 31 days after the executive's death, except that the plan
administrator may, in its discretion, accelerate payments.

     El Paso Benefits Protection Trust Agreement.  El Paso maintains a trust for
the purpose of funding certain of its employee benefit plans (including the El
Paso severance protection plans described above). The trust consists of a
trustee expense account, which is used to pay the fees and expenses of the
trustee, and a benefit account, which is made up of three subaccounts and used
to make payments to participants and beneficiaries in the participating plans.
The trust is revocable by El Paso at any time before a "threatened change in
control" (which is generally defined to include the commencement of actions that
would lead to a "change in control" (as defined under the El Paso Key Executive
Severance Protection Plan) of El Paso as to assets held in the trustee expense
account, but is not revocable (except as provided below) as to assets held in
the benefit account at any time. The trust generally becomes fully irrevocable
as to assets held in the trust upon a threatened change in control. The trust is
a grantor trust for federal tax purposes, and assets of the trust are subject to
claims by El Paso's general creditors in preference to the claims of plan
participants and beneficiaries. Upon a threatened change in control, El Paso
must deliver $1.5 million in cash to the trustee expense account. Prior to a
threatened change in control, El Paso may freely withdraw and substitute the
assets held in the benefit account, other than the initially funded amount;
however, no such assets may be withdrawn from the benefit account during a
threatened change in control period. Any assets contributed to

                                       133
<PAGE>

the trust during a threatened change in control period may be withdrawn if the
threatened change in control period ends and there has been no threatened change
in control. In addition, after a change in control of El Paso occurs, if the
trustee determines that the amounts held in the trust are less than "designated
percentages" (as defined in the Trust Agreement) with respect to each subaccount
in the benefit account, the trustee must make a written demand on El Paso to
deliver funds in an amount determined by the trustee sufficient to attain the
designed percentages. Following a change in control and if the trustee has not
been requested to pay benefits from any subaccount during a "determination
period" (as defined in the Trust Agreement), El Paso may make a written request
to the trustee to withdraw certain amounts which were allocated to the
subaccounts after the change in control occurred. The trust generally may be
amended or terminated at any time, provided that no amendment or termination may
result, directly or indirectly, in the return of any assets of the benefit
account to El Paso prior to the satisfaction of all liabilities under the
participating plans (except as described above) and no amendment may be made
unless El Paso, in its reasonable discretion, believes that such amendment would
have no material adverse effect on the amount of benefits payable under the
trust to participants. In addition, no amendment may be made after the
occurrence of a change in control which would (i) permit El Paso to withdraw any
assets from the trustee expense account, (ii) directly or indirectly reduce or
restrict the trustee's rights and duties under the trust, or (iii) permit El
Paso to remove the trustee following the date of the change in control.

     El Paso Alternative Benefits Program (ABP).  In 2001, Mr. Wise reduced the
balance of certain compensation payable to him under the El Paso Supplemental
Benefits Plan by $5,000,000, in exchange for the right to participate in the
ABP. The program provides for a loan to purchase a life insurance policy under a
family trust. The amount of the loan to Mr. Wise was $9,000,000. The trust is
the named beneficiary under the life insurance policy, and the loan with accrued
interest will be repaid, on an after-tax basis, with proceeds of the policy
after the participant's, or his spouse's death, whichever is later. The
compensation that was reduced had been awarded in prior years and was disclosed
as required in earlier proxy statements of El Paso. The cost of this program
will not exceed the cost El Paso would have paid as compensation with respect to
the reduced amounts. An amount of $2,608 was imputed as income in 2003 for Mr.
Wise and is included, to the extent required under the rules of the SEC, in the
"Other Annual Compensation" column to the Summary Compensation Table. This
program is now closed to new participants.

COMPENSATION PLANS

     El Paso 2001 Omnibus Incentive Compensation Plan.  This plan provides for
the grant to officers and key employees of El Paso and its subsidiaries of stock
options, stock appreciation rights, limited stock appreciation rights,
performance units and restricted stock. A maximum of 6,000,000 shares in the
aggregate may be subject to awards under this plan. The plan administrator
designates which employees are eligible to participate, the amount of any grant
and the terms and conditions (not otherwise specified in the plan) of such
grant. If a "change in control" (defined in substantially the same manner as
under the El Paso Key Executive Severance Protection Plan) of El Paso occurs:
(1) all outstanding stock options become fully exercisable; (2) stock
appreciation rights and limited stock appreciation rights become immediately
exercisable; (3) designated amounts of performance units become fully vested;
(4) all restrictions placed on awards of restricted stock automatically lapse;
and (5) the current year's target bonus amount becomes payable for each officer
participating in the plan within 30 days, assuming target levels of performance
were achieved by El Paso and the officer for the year in which the change in
control occurs, or the prior year if target levels have not been established for
the current year, except that no bonus amounts will become payable in connection
with a change in control that results solely from a change to the Board of
Directors of El Paso. The plan generally may be amended or terminated at any
time. Any amendment following a change in control that impairs participants'
rights requires participant consent.

     El Paso 1999 Omnibus Incentive Compensation Plan and 1995 Omnibus
Compensation Plan  -- Terminated Plans.  These plans provided for the grant to
eligible officers and key employees of El Paso and its subsidiaries of stock
options, stock appreciation rights, limited stock appreciation rights,
performance units and restricted stock. These plans have been replaced by the El
Paso 2001 Omnibus Incentive Compensation Plan. Although these plans have been
terminated with respect to new grants, certain stock options and shares

                                       134
<PAGE>

of restricted stock remain outstanding under them. If a "change in control" of
El Paso occurs, all outstanding stock options become fully exercisable and
restrictions placed on restricted stock lapse. For purposes of the plans, the
term "change in control" has substantially the same meaning given such term in
the El Paso Key Executive Severance Protection Plan.

     El Paso Strategic Stock Plan.  This plan is an equity compensation plan
that has not been approved by the stockholders. This plan provides for the grant
of stock options, stock appreciation rights, limited stock appreciation rights
and shares of restricted stock to non-employee members of the Board of
Directors, officers and key employees of El Paso and its subsidiaries primarily
in connection with El Paso's strategic acquisitions. A maximum of 4,000,000
shares in the aggregate may be subject to awards under this plan. The plan
administrator determines which employees are eligible to participate, the amount
of any grant and the terms and conditions (not otherwise specified in the plan)
of such grant. If a change in control, as defined earlier under the El Paso Key
Executive Severance Protection Plan, of El Paso occurs: (1) all outstanding
stock options become fully exercisable; (2) stock appreciation rights and
limited stock appreciation rights become immediately exercisable; and (3) all
restrictions placed on awards of restricted stock automatically lapse. The plan
generally may be amended or terminated at any time, provided that no amendment
or termination may impair participants' rights under the plan.

     El Paso Omnibus Plan for Management Employees.  This plan is an equity
compensation plan which has not been approved by the stockholders. This plan
provides for the grant of stock options, stock appreciation rights, limited
stock appreciation rights and shares of restricted stock to salaried employees
(other than employees covered by a collective bargaining agreement) of El Paso
and its subsidiaries. A maximum of 58,000,000 shares in the aggregate may be
subject to awards under this plan. If a change in control, as defined earlier
under the El Paso Key Executive Severance Protection Plan, of El Paso occurs:
(1) all outstanding stock options become fully exercisable; (2) stock
appreciation rights and limited stock appreciation rights become immediately
exercisable; and (3) all restrictions placed on awards of restricted stock
automatically lapse. The plan generally may be amended or terminated at any
time, provided that no amendment or termination may impair participants' rights
under the plan.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
         RELATED STOCKHOLDER MATTERS

     None of our Common Stock is held by any director or executive officer. No
family relationship exists between any of our directors or executive officers.
The following information relates to the only entity known to us to be the
beneficial owner, as of August 31, 2004, of more than five percent of our voting
securities.

<Table>
<Caption>
              TITLE OF                                           AMOUNT AND NATURE OF   PERCENT
               CLASS                          NAME               BENEFICIAL OWNERSHIP   OF CLASS
              --------                        ----               --------------------   --------
    <S>                           <C>                            <C>                    <C>
    Common Stock                  El Paso Corporation                1,000 shares         100%
                                  1001 Louisiana Street
                                  Houston, Texas 77002
</Table>

     The following table sets forth, as of September 15, 2004 (unless otherwise
indicated), certain information with respect to the following individuals to the
extent they own shares of common stock of El Paso, our parent.

<Table>
<Caption>
                                                                BENEFICIAL OWNERSHIP
                                                                     (EXCLUDING           STOCK                     PERCENT
TITLE OF CLASS             NAME OF BENEFICIAL OWNER                  OPTIONS)(1)        OPTIONS(2)       TOTAL      OF CLASS
--------------             ------------------------             ---------------------   ----------     ----------   --------
<S>             <C>                                             <C>                     <C>            <C>          <C>
Common Stock    D.L. Foshee...................................          507,199            200,000        707,199        *
Common Stock    D.D. Scott....................................          169,095            140,247        309,342        *
Common Stock    R.W. Baker....................................          145,240            183,709        328,949        *
Common Stock    P.A. Heeg.....................................           72,803(3)         166,730        239,533        *
Common Stock    R.L. Kuehn, Jr. ..............................          313,500(4)         614,300        927,800        *
Common Stock    W.A. Wise.....................................        1,796,658(5)       1,621,917(6)   3,418,575        *
Common Stock    Directors and executive officers as a group 6
                persons total, including those individuals
                listed above..................................        3,004,495          2,926,903      5,931,398       .1%
</Table>

                                       135
<PAGE>

---------------

 * Less than 1%

(1) The individuals named in the table have sole voting and investment power
    with respect to shares of El Paso common stock beneficially owned. This
    column also includes shares of common stock held in the El Paso Benefits
    Protection Trust (as of September 15, 2004) as a result of deferral
    elections made in accordance with El Paso's benefit plans. These individuals
    share voting power with the trustee under that plan and receive dividends on
    such shares, but do not have the power to dispose of, or direct the
    disposition of, such shares until such shares are distributed. In addition,
    some shares of common stock reflected in this column for certain individuals
    are subject to restrictions.

(2) The directors and executive officers have the right to acquire the shares of
    common stock reflected in this column within 60 days of September 15, 2004,
    through the exercise of stock options.

(3) Ms. Heeg's stock ownership is as of December 31, 2003, when Ms. Heeg left
    the company.

(4) Mr. Kuehn's beneficial ownership excludes 27,720 shares of El Paso common
    stock owned by his wife or children, of which Mr. Kuehn disclaims any
    beneficial ownership.

(5) Mr. Wise's stock ownership is as of March 12, 2003 when Mr. Wise left El
    Paso. Mr. Wise's beneficial ownership excludes 400 shares of El Paso common
    stock owned by his children under the Uniform Gifts to Minors Act, of which
    Mr. Wise disclaims any beneficial ownership.

(6) Includes 98,000 stock options held in the William & Marie Wise Family Ltd.
    Partnership.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     We are currently a wholly owned subsidiary of El Paso. El Paso owns 100% of
our outstanding stock and has the right to elect all of our directors. We share
office space, personnel, and other administrative services with El Paso. In
addition, there are other shared personnel that may include officers who
function as both our representative and those of El Paso and its subsidiaries.
Some of these shared directors, officers and employees own and are awarded from
time to time shares, or options to purchase shares, of El Paso; accordingly,
their financial interests may not always be aligned completely with ours.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

AUDIT FEES

     The Audit Fees for the years ended December 31, 2003 and 2002 of $300,000
and $250,000 were for professional services rendered by PricewaterhouseCoopers
LLP for the audits of the consolidated financial statements of El Paso CGP
Company.

ALL OTHER FEES

     No other audit-related, tax or other services were provided by our auditors
for the years ended December 31, 2003 and 2002.

POLICY FOR APPROVAL OF AUDIT AND NON-AUDIT FEES

     We are a wholly owned direct subsidiary of El Paso and do not have a
separate audit committee. El Paso's Audit Committee has adopted a pre-approval
policy for audit and non-audit services. For a description of El Paso's
pre-approval policies for audit and non-audit related services, see El Paso
Corporation's 2004 proxy statement.

                                       136
<PAGE>

                                    PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.

     (a) THE FOLLOWING DOCUMENTS ARE FILED AS PART OF THIS REPORT:

     1. Financial statements.

     Our consolidated financial statements are included in Part II, Item 8 of
this report:

<Table>
<Caption>
                                                              PAGE
                                                              ----
<S>                                                           <C>
Consolidated Statements of Income...........................   55
Consolidated Balance Sheets.................................   56
Consolidated Statements of Cash Flows.......................   58
Consolidated Statements of Stockholder's Equity.............   59
Consolidated Statements of Comprehensive Income.............   60
Notes to Consolidated Financial Statements..................   61
Report of Independent Registered Public Accounting Firm.....  120
</Table>

     2. Financial statement schedules and supplementary information required to
be submitted.

<Table>
<S>                                                           <C>
Schedule II -- Valuation and Qualifying Accounts............  121
</Table>

          Schedules other than those listed above are omitted because they are
     not applicable.

<Table>
<S>                                                           <C>  <C>
3. Exhibit list.............................................  138
</Table>

                                       137
<PAGE>

                              EL PASO CGP COMPANY

                                  EXHIBIT LIST

                               DECEMBER 31, 2003

     Each exhibit identified below is filed as a part of this report. Exhibits
not incorporated by reference to a prior filing are designated by an "*"; all
exhibits not so designated are incorporated herein by reference to a prior
filing as indicated.

<Table>
<Caption>
EXHIBIT
 NUMBER                            DESCRIPTION
-------                            -----------
<S>        <C>
  10.A     $3,000,000,00 Revolving Credit Agreement dated as of April
           16, 2003 among El Paso Corporation, El Paso Natural Gas
           Company, Tennessee Gas Pipeline Company and ANR Pipeline
           Company, as Borrowers, the Lenders Party thereto, and
           JPMorgan Chase Bank, as Administrative Agent, ABN AMRO Bank
           N.V. and Citicorp North America, Inc., as Co-Document
           Agents, Bank of America, N.A. and Credit Suisse First
           Boston, as Co-Syndication Agents, J.P. Morgan Securities
           Inc. and Citigroup Global Markets Inc., as Joint Bookrunners
           and Co-Lead Arrangers. (Exhibit 99.1 to El Paso
           Corporation's Form 8-K filed April 18, 2003).

 *10.A.1   First Amendment to the $3,000,000,000 Revolving Credit
           Agreement and Waiver dated as of March 17, 2004 among El
           Paso Corporation, El Paso Natural Gas Company, Tennessee Gas
           Pipeline Company, ANR Pipeline Company and Colorado
           Interstate Gas Company, as Borrowers, the Lender and
           JPMorgan Chase Bank, as Administrative Agent, ABN AMRO Bank
           N.V. and Citicorp North America, Inc., as Co-Documentation
           Agents, Bank of America, N.A. and Credit Suisse First
           Boston, as Co-Syndication Agents.

 *10.A.2   Second Waiver to the $3,000,000,000 Revolving Credit
           Agreement dated as of June 15, 2004 among El Paso
           Corporation, El Paso Natural Gas Company, Tennessee Gas
           Pipeline Company, ANR Pipeline Company and Colorado
           Interstate Gas Company, as Borrowers, the Lenders party
           thereto and JPMorgan Chase Bank, as Administrative Agent,
           ABN AMRO Bank N.V. and Citicorp North America, Inc., as
           Co-Documentation Agents, Bank of America, N.A. and Credit
           Suisse First Boston, as Co-Syndication Agents.

 *10.A.3   Second Amendment to the $3,000,000,000 Revolving Credit
           Agreement and Third Waiver dated as of August 6, 2004 among
           El Paso Corporation, El Paso Natural Gas Company, Tennessee
           Gas Pipeline Company, ANR Pipeline Company and Colorado
           Interstate Gas Company, as Borrowers, the Lenders party
           thereto and JPMorgan Chase Bank, as Administrative Agent,
           ABN AMRO Bank N.V. and Citicorp North America, Inc., as
           Co-Documentation Agents, Bank of America, N.A. and Credit
           Suisse First Boston, as Co-Syndication Agents (Exhibit 99.B
           to our Form 8-K filed August 10, 2004).
</Table>

                                       138
<PAGE>

<Table>
<Caption>
EXHIBIT
 NUMBER                            DESCRIPTION
-------                            -----------
<S>        <C>

  10.B     Master Settlement Agreement dated as of June 24, 2003, by
           and between, on the one hand, El Paso Corporation, El Paso
           Natural Gas Company, and El Paso Merchant Energy, L.P.; and,
           on the other hand, the Attorney General of the State of
           California, the Governor of the State of California, the
           California Public Utilities Commission, the California
           Department of Water Resources, the California Energy
           Oversight Board, the Attorney General of the State of
           Washington, the Attorney General of the State of Oregon, the
           Attorney General of the State of Nevada, Pacific Gas &
           Electric Company, Southern California Edison Company, the
           City of Los Angeles, the City of Long Beach, and classes
           consisting of all individuals and entities in California
           that purchased natural gas and/or electricity for use and
           not for resale or generation of electricity for the purpose
           of resale, between September 1, 1996 and March 20, 2003,
           inclusive, represented by class representatives Continental
           Forge Company, Andrew Berg, Andrea Berg, Gerald J. Marcil,
           United Church Retirement Homes of Long Beach, Inc., doing
           business as Plymouth West, Long Beach Brethren Manor, Robert
           Lamond, Douglas Welch, Valerie Welch, William Patrick Bower,
           Thomas L. French, Frank Stella, Kathleen Stella, John
           Clement Molony, SierraPine, Ltd., John Frazee and Jennifer
           Frazee, John W.H.K. Phillip, and Cruz Bustamante (Exhibit
           10.HH to El Paso Corporation's 2003 Second Quarter Form
           10-Q).

 *10.C     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.

 *21.      Subsidiaries of El Paso CGP Company.

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

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

 *32.A     Certification of Chief Executive Officer pursuant to 18
           U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the
           Sarbanes-Oxley Act of 2002.

 *32.B     Certification of Chief Financial Officer pursuant to 18
           U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the
           Sarbanes-Oxley Act of 2002.
</Table>

     (b) REPORTS ON FORM 8-K

<Table>
        <S>                <C>
        February 2, 2004   El Paso Corporation, our parent company, provided an update
                           on our Production segment operations, which includes our
                           production operations (includes information furnished under
                           Item 9).



        February 17, 2004  El Paso Corporation, our parent company, announced that it
                           had completed its annual review of natural gas and oil
                           reserve estimates. El Paso provided its proved reserve
                           estimate and production update (which included ours).



        March 10, 2004     El Paso Corporation, our parent company, announced that it
                           would delay the release of its fourth quarter 2003 earnings
                           pending the completion of a review of the impact of its
                           recently announced reserve revision.



        May 3, 2004        El Paso Corporation, our parent company, announced findings
                           of an independent review of the Audit Committee of its Board
                           of Directors concerning the revisions to its oil and natural
                           gas reserves (including our reserves).
</Table>

                                       139
<PAGE>
<Table>
        <S>                <C>



        May 28, 2004       El Paso Corporation, our parent company, issued a press
                           release providing a progress report on its long-range plan,
                           financial and operational information for the fourth quarter
                           of 2003 and the first quarter of 2004, and an update on the
                           filing of El Paso Corporation, El Paso Production Holding
                           Company, and our 2003 Form 10-K and the first quarter 2004
                           Form 10-Q (includes information furnished under Item 12).



        June 15, 2004      El Paso Corporation, our parent company, announced that the
                           Master Settlement Agreement related to the western energy
                           crisis became effective on June 11, 2004.



        June 17, 2004      El Paso Corporation, our parent company, announced that it
                           had received waivers on its $3 billion revolving credit
                           facility and certain other financings.



        June 22, 2004      El Paso Corporation, our parent company, announced that it
                           had closed the sale of its interests in UCF for
                           approximately $21 million.



        June 29, 2004      El Paso Corporation, our parent company, provided an update
                           on its strategy plan for its production business, which
                           includes our business.



        August 10, 2004    El Paso Corporation, our parent company, announced its
                           anticipated timeline for the filing of its and our Annual
                           Report on Form 10-K.
</Table>

     We also furnished information to the SEC in Item 9 (now Item 7.01) and Item
12 (now Item 2.02) Current Reports on Form 8-K. These Forms 8-K are not
considered to be "filed" for purposes of Section 18 of the Securities Exchange
Act of 1934 and are not subject to the liabilities of that section.

                                       140
<PAGE>

                                   SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, as amended, El Paso CGP Company has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly authorized
on the 12 day of October 2004.

                                        EL PASO CGP COMPANY
                                        Registrant

                                                /s/ DOUGLAS L. FOSHEE
                                        ----------------------------------------
                                                   Douglas L. Foshee
                                         President and Chief Executive Officer

     Pursuant to the requirements of the Securities Exchange Act of 1934, as
amended, this report has been signed below by the following persons on behalf of
El Paso CGP Company and in the capacities and on the dates indicated:

<Table>
<Caption>
                     SIGNATURE                                    TITLE                      DATE
                     ---------                                    -----                      ----
<S>                                                  <C>                               <C>

               /s/ DOUGLAS L. FOSHEE                    President, Chief Executive     October 12, 2004
---------------------------------------------------   Officer, Chairman of the Board
                (Douglas L. Foshee)                            and Director
                                                      (Principal Executive Officer)

                /s/ D. DWIGHT SCOTT                  Executive Vice President, Chief   October 12, 2004
---------------------------------------------------   Financial Officer and Director
                 (D. Dwight Scott)                    (Principal Financial Officer)

                /s/ ROBERT W. BAKER                     Executive Vice President,      October 12, 2004
---------------------------------------------------    General Counsel and Director
                 (Robert W. Baker)

               /s/ JEFFREY I. BEASON                    Senior Vice President and      October 12, 2004
---------------------------------------------------             Controller
                (Jeffrey I. Beason)                   (Principal Accounting Officer)
</Table>

                                       141
<PAGE>

                                 EXHIBIT INDEX

     Each exhibit identified below is filed as a part of this report. Exhibits
not incorporated by reference to a prior filing are designated by an "*"; all
exhibits not so designated are incorporated herein by reference to a prior
filing as indicated.

<Table>
<Caption>
EXHIBIT
 NUMBER                            DESCRIPTION
-------                            -----------
<S>        <C>
  10.A     $3,000,000,00 Revolving Credit Agreement dated as of April
           16, 2003 among El Paso Corporation, El Paso Natural Gas
           Company, Tennessee Gas Pipeline Company and ANR Pipeline
           Company, as Borrowers, the Lenders Party thereto, and
           JPMorgan Chase Bank, as Administrative Agent, ABN AMRO Bank
           N.V. and Citicorp North America, Inc., as Co-Document
           Agents, Bank of America, N.A. and Credit Suisse First
           Boston, as Co-Syndication Agents, J.P. Morgan Securities
           Inc. and Citigroup Global Markets Inc., as Joint Bookrunners
           and Co-Lead Arrangers. (Exhibit 99.1 to El Paso
           Corporation's Form 8-K filed April 18, 2003).

 *10.A.1   First Amendment to the $3,000,000,000 Revolving Credit
           Agreement and Waiver dated as of March 15, 2004 among El
           Paso Corporation, El Paso Natural Gas Company, Tennessee Gas
           Pipeline Company, ANR Pipeline Company and Colorado
           Interstate Gas Company, as Borrowers, the Lender and
           JPMorgan Chase Bank, as Administrative Agent, ABN AMRO Bank
           N.V. and Citicorp North America, Inc., as Co-Documentation
           Agents, Bank of America, N.A. and Credit Suisse First
           Boston, as Co-Syndication Agents.

 *10.A.2   Second Waiver to the $3,000,000,000 Revolving Credit
           Agreement dated as of June 15, 2004 among El Paso
           Corporation, El Paso Natural Gas Company, Tennessee Gas
           Pipeline Company, ANR Pipeline Company and Colorado
           Interstate Gas Company, as Borrowers, the Lenders party
           thereto and JPMorgan Chase Bank, as Administrative Agent,
           ABN AMRO Bank N.V. and Citicorp North America, Inc., as
           Co-Documentation Agents, Bank of America, N.A. and Credit
           Suisse First Boston, as Co-Syndication Agents.

  10.A.3   Second Amendment to the $3,000,000,000 Revolving Credit
           Agreement and Third Waiver dated as of August 6, 2004 among
           El Paso Corporation, El Paso Natural Gas Company, Tennessee
           Gas Pipeline Company, ANR Pipeline Company and Colorado
           Interstate Gas Company, as Borrowers, the Lenders party
           thereto and JPMorgan Chase Bank, as Administrative Agent,
           ABN AMRO Bank N.V. and Citicorp North America, Inc., as
           Co-Documentation Agents, Bank of America, N.A. and Credit
           Suisse First Boston, as Co-Syndication Agents (Exhibit 99.B
           to our Form 8-K filed August 10, 2004).

  10.B     Master Settlement Agreement dated as of June 24, 2003, by
           and between, on the one hand, El Paso Corporation, El Paso
           Natural Gas Company, and El Paso Merchant Energy, L.P.; and,
           on the other hand, the Attorney General of the State of
           California, the Governor of the State of California, the
           California Public Utilities Commission, the California
           Department of Water Resources, the California Energy
           Oversight Board, the Attorney General of the State of
           Washington, the Attorney General of the State of Oregon, the
           Attorney General of the State of Nevada, Pacific Gas &
           Electric Company, Southern California Edison Company, the
           City of Los Angeles, the City of Long Beach, and classes
           consisting of all individuals and entities in California
           that purchased natural gas and/or electricity for use and
           not for resale or generation of electricity for the purpose
           of resale, between September 1, 1996 and March 20, 2003,
           inclusive, represented by class representatives Continental
           Forge Company, Andrew Berg, Andrea Berg, Gerald J. Marcil,
           United Church Retirement Homes of Long Beach, Inc., doing
           business as Plymouth West, Long Beach Brethren Manor, Robert
           Lamond, Douglas Welch, Valerie Welch, William Patrick Bower,
           Thomas L. French, Frank Stella, Kathleen Stella, John
           Clement Molony, SierraPine, Ltd., John Frazee and Jennifer
           Frazee, John W.H.K. Phillip, and Cruz Bustamante (Exhibit
           10.HH to El Paso Corporation's 2003 Second Quarter Form
           10-Q).
</Table>
<PAGE>

<Table>
<Caption>
EXHIBIT
 NUMBER                            DESCRIPTION
-------                            -----------
<S>        <C>

 *10.C     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.

 *21.      Subsidiaries of El Paso CGP Company.

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

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

 *32.A     Certification of Chief Executive Officer pursuant to 18
           U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the
           Sarbanes-Oxley Act of 2002.

 *32.B     Certification of Chief Financial Officer pursuant to 18
           U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the
           Sarbanes-Oxley Act of 2002.
</Table>