<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, 2002

                                       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                         (I.R.S. Employer
      of 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:

<Table>
<Caption>
                                                               NAME OF EACH EXCHANGE
                    TITLE OF EACH CLASS                         ON WHICH REGISTERED
                    -------------------                        ---------------------
<S>                                                           <C>
8.375% Coastal Trust Preferred Securities issued by Coastal
                          Finance I                           New York Stock Exchange
</Table>

        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 [X]  No [ ]

    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 AT 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 March 26, 2003:
1,000

    EL PASO CGP COMPANY MEETS THE CONDITIONS OF GENERAL INSTRUCTION I(1)(a) AND
(b) TO FORM 10-K AND IS, THEREFORE, FILING THIS REPORT WITH A REDUCED DISCLOSURE
FORMAT AS PERMITTED BY SUCH INSTRUCTION.

                   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..................................................   18
Item 3.     Legal Proceedings...........................................   18
Item 4.     Submission of Matters to a Vote of Security Holders.........    *

                                   PART II

Item 5.     Market for Registrant's Common Equity and Related
              Stockholder Matters.......................................   18
Item 6.     Selected Financial Data.....................................    *
Item 7.     Management's Discussion and Analysis of Financial Condition
              and Results of Operations.................................   19
            Risk Factors and Cautionary Statement for Purposes of the
              "Safe Harbor" Provisions of the Private Securities
              Litigation Reform Act of 1995.............................   34
Item 7A.    Quantitative and Qualitative Disclosures About Market
              Risk......................................................   44
Item 8.     Financial Statements and Supplementary Data.................   46
Item 9.     Changes in and Disagreements with Accountants on Accounting
              and Financial Disclosure..................................  108

                                   PART III

Item 10.    Directors and Executive Officers of the Registrant..........    *
Item 11.    Executive Compensation......................................    *
Item 12.    Security Ownership of Certain Beneficial Owners and
              Management................................................    *
Item 13.    Certain Relationships and Related Transactions..............    *
Item 14.    Controls and Procedures.....................................  108

                                   PART IV

Item 15.    Exhibits, Financial Statement Schedules and Reports on Form
              8-K.......................................................  109
            Signatures..................................................  120
            Certifications..............................................  121
</Table>

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

* We have not included a response to this item in this document since no
  response is required pursuant to the reduced disclosure format permitted by
  General Instruction I to Form 10-K.

     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 gas equivalents
MBbls    = thousand barrels
Mcf      = thousand cubic feet
Mcfe     = thousand cubic feet of gas equivalents
Mgal     = thousand gallons
MMBbls   = million barrels
MMBtu    = million British thermal units
MMcf     = million cubic feet
MMcfe    = million cubic feet of gas equivalents
MTons    = thousand tons
MWh      = megawatt hours
Tcfe     = trillion cubic feet of 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. 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", or "Coastal", we are describing
El Paso CGP Company and/or our subsidiaries.

                                        i
<PAGE>

                                     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. On January 30, 2001, we changed
our name from The Coastal Corporation to El Paso CGP Company.

     Our principal operations include:

        - natural gas transportation, gathering, processing and storage;

        - natural gas and oil exploration, development and production;

        - power generation;

        - energy infrastructure facility development and operation;

        - petroleum refining; and

        - chemicals production.

                                    SEGMENTS

     Our operations are segregated into four primary business segments:
Pipelines, Production, Field Services and Merchant Energy. These 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. As future developments in our business
occur and as we carry out our ongoing strategy and plans, we will continue to
assess the appropriateness of our business segments. For the operating results
and identifiable assets by segment, you should see Part II, Item 8, Financial
Statements and Supplementary Data, Note 18, which is incorporated herein by
reference.

     Our Pipelines segment owns or has interests in approximately 19,600 miles
of interstate natural gas pipelines in the U.S. and internationally. In the
U.S., our systems connect the nation's principal natural gas supply regions to
the four largest consuming regions in the U.S.: the Gulf Coast, California, the
Northeast and the Midwest. Our U.S. pipeline systems also own or have interests
in over 280 Bcf of storage capacity used to provide a variety of services to our
customers. Our international pipeline operations include access between our U.S.
based systems and Canada.

     Our Production segment conducts our natural gas and oil exploration and
production activities. Domestically, we lease approximately 1 million net acres
in 10 states, including Texas, Utah, and in the Gulf of Mexico. We also have
exploration and production rights in Australia, Bolivia, Brazil, Canada, Hungary
and Indonesia. During 2002, daily equivalent natural gas production exceeded 0.8
Bcfe/d, and our reserves at December 31, 2002, were approximately 2.3 Tcfe.

     Our Field Services segment conducts our midstream activities. These
services include gathering natural gas from approximately 2,900 natural gas
wells with approximately 3,800 miles of natural gas gathering and natural gas
liquids (NGL) pipelines, and 12 natural gas processing, treating and
fractionation facilities located in producing regions of the south Texas, south
Louisiana, Mid-Continent and Rocky Mountain regions.

     Our Merchant Energy segment consists of two primary divisions: global power
and petroleum. We are an owner of electric generating capacity and own or have
interests in 19 power plants in 8 countries. We operate three refineries that
have the capacity to process approximately 438 MBbls of crude oil per day and
produce a variety of petroleum products. We also produce agricultural and
industrial chemicals at four facilities in the U.S. On February 5, 2003, El Paso
announced its intent to sell our remaining petroleum and chemical assets, except
for our Aruba refinery. During 2002 and the first part of 2003, El Paso also
completed or announced several asset sales including the sale of our coal mining
assets and operations, petroleum assets and interests in power projects.

                                        1
<PAGE>

                               PIPELINES SEGMENT

     Our Pipelines segment provides natural gas transmission, storage, gathering
and related services in the U.S. and internationally. We conduct our activities
primarily through three wholly owned and two partially owned interstate
transmission systems along with five 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, 2002
                                                                    ------------------------------   AVERAGE THROUGHPUT(1)
     TRANSMISSION                       SUPPLY AND                  MILES OF    DESIGN    STORAGE    ---------------------
        SYSTEM                         MARKET REGION                PIPELINE   CAPACITY   CAPACITY   2002    2001    2000
     ------------                      -------------                --------   --------   --------   -----   -----   -----
                                                                               (MMcf/d)    (Bcf)           (BBtu/d)
<S>                      <C>                                        <C>        <C>        <C>        <C>     <C>     <C>
ANR Pipeline             Extends from Louisiana, Oklahoma, Texas    10,600       6,450     207       3,691   3,776   3,807
  (ANR)                  and the Gulf of Mexico to the midwestern
                         and northeastern 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        1,563   1,448   1,383
  (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        1,860     --        1,194   1,017     832
  (WIC)                  Powder River Basin to various pipeline
                         interconnections near Cheyenne, Wyoming.
</Table>

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

Partially Owned Interstate Transmission Systems
<Table>
<Caption>
                                                                      AS OF DECEMBER 31, 2002                 AVERAGE
                                                                 ----------------------------------        THROUGHPUT(1)
        TRANSMISSION                   SUPPLY AND                OWNERSHIP   MILES OF     DESIGN       ---------------------
           SYSTEM                     MARKET REGION              INTEREST    PIPELINE   CAPACITY(1)    2002    2001    2000
        ------------                  -------------              ---------   --------   -----------    -----   -----   -----
                                                                 (PERCENT)               (MMcf/d)            (BBtu/d)
<S>                           <C>                                <C>         <C>        <C>            <C>     <C>     <C>
Alliance Pipeline(2)          Extends from western Canada
                              to Chicago.                            2        2,345        1,537       1,476   1,479     105

Great Lakes Gas Transmission  Extends from the Manitoba-            50        2,115        2,895       2,378   2,224   2,477
                              Minnesota border to the
                              Michigan-Ontario border
                              at St. Clair, Michigan.
</Table>

---------------
(1) Volumes represent the systems' total design capacity and average throughput
    and are not adjusted for our ownership interest.

(2) The Alliance pipeline project commenced operations in the fourth quarter of
    2000. We sold 12.3 percent of our equity interest in the system during the
    fourth quarter of 2002, and the remaining 2.1 percent equity interest in the
    first quarter of 2003.

     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, 2002
                                                              -----------------------
                                                              OWNERSHIP     STORAGE
STORAGE ENTITY                                                INTEREST    CAPACITY(1)   LOCATION
--------------                                                ---------   -----------   --------
                                                              (PERCENT)      (Bcf)
<S>                                                           <C>         <C>           <C>
ANR Storage................................................    100          56          Michigan
Blue Lake Gas Storage......................................     75          47          Michigan
Eaton Rapids Gas Storage...................................     50          13          Michigan
Steuben Gas Storage........................................     50           6          New York
Young Gas Storage..........................................     48           6          Colorado
</Table>

---------------
(1) Includes a total of 81 Bcf contracted to affiliates. Storage capacity is
    under long-term contracts and is not adjusted for our ownership interest.

                                        2
<PAGE>

     We have a number of transmission system expansion projects that have been
approved by the Federal Energy Regulatory Commission (FERC) as follows:

<Table>
<Caption>
TRANSMISSION                                                                                             ANTICIPATED
   SYSTEM           PROJECT        CAPACITY                         DESCRIPTION                        COMPLETION DATE
------------        -------        --------                         -----------                        ---------------
                                   (MMcf/d)
<S>            <C>                 <C>        <C>                                                      <C>
ANR            Westleg Wisconsin     218      To increase capacity of ANR's existing system by         November 2004
                   Expansion                  looping the Madison lateral and by enlarging the Beloit
                                              lateral through abandonment and replacement.

CIG               Valley Line         92      Installation of additional natural gas compression and   December 2003
                                              air blending facilities to expand the deliverability of
                                              the Front Range system.
</Table>

     Our transportation, storage and related services (transportation services)
revenues consist of reservation and usage revenues. In 2002, approximately 92
percent of our transportation services revenues were attributable to a capacity
reservation or a demand charge paid by firm customers. These firm customers are
obligated to pay a monthly demand charge, regardless of the amount of natural
gas they transport or store, for the term of their contracts. The remaining 8
percent of our transportation services revenue was attributable to usage charges
based largely on the volumes of gas actually transported or stored on our
pipeline systems.

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, terminalling
and related services;

     - certification and construction of new facilities;

     - extension or abandonment of facilities;

     - maintenance of accounts and records;

     - relationships between pipeline and marketing 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 return on our invested
capital. Consequently, 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.

     In Canada, our pipeline activities are regulated by the National Energy
Board. Similar to the FERC, the National Energy Board governs tariffs and rates,
and the construction and operation of natural gas pipelines in Canada.

     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. We believe that our systems are
in material compliance with the applicable requirements.

     A discussion of significant rate and regulatory matters is included in Part
II, Item 8, Financial Statements and Supplementary Data, Note 16, and is
incorporated herein by reference.

                                        3
<PAGE>

  Markets and Competition

     The following table details our markets and competition on each of our
wholly owned pipeline systems as of December 31, 2002:

<Table>
<Caption>
TRANSMISSION
   SYSTEM       CUSTOMER INFORMATION(1)          CONTRACT INFORMATION                      COMPETITION
------------  ----------------------------  -------------------------------  ---------------------------------------
<S>           <C>                           <C>                              <C>
ANR           Approximately 238 firm and    Approximately 643 firm           In the Midwest markets, ANR competes
                interruptible customers     contracts                        with other interstate and intrastate
                                            Contracted capacity: 98%         pipeline companies and local
                                            Weighted average remaining       distribution companies in the
                                            contract term of approximately   transportation and storage of natural
                                            four years                       gas. In the Northeast markets, ANR
                                                                             competes with other interstate
              Major Customer:                                                pipelines serving electric generation
                We Energies                                                  and local distribution companies. Also,
                  (1,138 BBtu/d)            Contract terms expire in         Wisconsin Gas, which operates under the
                                            2003-2010.                       name We Energies, is a sponsor of
                                                                             Guardian Pipeline, which was placed in
                                                                             service in December 2002. Guardian will
                                                                             serve a portion of We Energies
                                                                             transportation requirements and will
                                                                             compete directly with ANR.

CIG           Approximately 125 firm and    Approximately 170 firm           CIG serves two major markets, the
                interruptible customers     contracts                        "on-system" market, consisting of
                                            Contracted capacity: 100%        utilities and other customers located
                                            Weighted average remaining       along the front range of the Rocky
                                            contract term of approximately   Mountains in Colorado and Wyoming, and
                                            seven years                      the "off-system" market, consisting of
              Major Customer:                                                the transportation of Rocky Mountain
                Public Service Company of                                    production from multiple supply basins
                  Colorado                                                   to interconnections with other
                  (1,095 BBtu/d)                                             pipelines bound for the Midwest, the
                  (462 BBtu/d)              Contract term expires in 2007.   Southwest, California and the Pacific
                                            Contract term expires in         Northwest. Competition for the
                                            2008-2025.                       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 the
                                                                             off-system market consists of other
                                                                             interstate pipelines that are directly
                                                                             connected to CIG's supply sources and
                                                                             transport these volumes to markets in
                                                                             the West, Northwest, Southwest and
                                                                             Midwest.

WIC           Approximately 43 firm and     Approximately 47 firm contracts  WIC competes with eight interstate
                interruptible customers     Contracted capacity: 100%        pipelines and one intrastate pipeline
                                            Weighted average remaining       for its mainline supply. The Overthrust
                                            contract term of approximately   supply basin, which historically
                                            six years                        supplies the WIC mainline, has been
                                                                             declining and there has been increased
              Major Customers:                                               competition from the pipelines serving
                Williams Energy Marketing                                    the West and Northwest market areas for
                  and Trading                                                this gas supply. To replace these
                  (340 BBtu/d)              Contract terms expire in         volumes, WIC is pursuing access to new
                Western Gas Resources       2003-2013.                       supply sources. Additionally, WIC's one
                  (272 BBtu/d)                                               Bcf expandable Medicine Bow lateral is
                Colorado Interstate Gas     Contract terms expire in         the primary source of transportation
                  Company                   2003-2013.                       for increasing volumes of Powder River
                  (247 BBtu/d)                                               Basin supply. Currently there are two
                CMS Field Services                                           other interstate pipelines that
                  (234 BBtu/d)              Contract terms expire in         transport limited volumes out of this
                                            2003-2007.                       basin. Upon the approval and
                                                                             construction of the new Cheyenne Plains
                                            Contract terms expire in         project(2), WIC will have an increased
                                            2004-2013.                       outlet to mid-continent markets.
</Table>

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

(1) Includes natural gas producers, marketers, end-users and other natural gas
    transmission, distribution and electric generation companies.

(2)The Cheyenne Plains project is a new 30-inch diameter pipeline proposed by us
   to transport natural gas from the Cheyenne hub to the confluence of several
   pipelines near Greensburg, Kansas. This pipeline is anticipated to be in
   service in mid-2005 depending on the timing of regulatory approval.

     Electric power generation is one of the fastest growing demand sectors 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 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
will result in lower growth in the gas demand in such regions associated with
new power generation facilities.

     As our pipeline contracts expire, our ability to extend our existing
contracts or re-market expiring capacity is dependent on competitive
alternatives, the regulatory environment at the federal, state and local levels
and market supply and demand factors at the relevant dates these contracts are
extended or expire. The duration of new or 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.

     As a result of the rating agencies downgrading the credit rating of several
members of the energy sector, including energy trading companies, and placing
them on negative credit watch, the creditworthiness of some customers has
deteriorated. We have taken actions to mitigate our exposure by requesting these
companies provide us with letters of credit or prepayments as permitted by our
tariffs. Our tariffs permit us to request additional credit assurance from our
shippers equal to the cost of performing transportation services for various
periods as specified in each tariff. If these companies experience financial
difficulties or file for Chapter 11 bankruptcy protection and our contracts are
not assumed by other counterparties, or if the capacity is unavailable for
resale, it could have a material adverse effect on our financial position,
operating results or cash flows.

                               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. Domestically, 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.

     Strategically, Production emphasizes disciplined investment criteria and
manages its existing production portfolio to maximize volumes and minimize
costs. It employs geophysical technology and seismic data processing to identify
economic hydrocarbon reserves. Production's deep drilling capabilities and
hydraulic fracturing technology allow it to optimize production with high-rate
completions at competitive reserve replacement costs. Production maintains an
active drilling program that capitalizes on its land and seismic holdings. It
also acquires production properties subject to acceptable investment return
criteria.

  Natural Gas and Oil Reserves

     The table below details Production's proved reserves at December 31, 2002.
Information in this table is based on the reserve report dated January 1, 2003,
prepared internally by Production and reviewed by Huddleston & Co., Inc. 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. These reserves include 465,783 MMcfe of
production delivery commitments under financing arrangements that extend through
2042.

                                        5
<PAGE>

The financing arrangement supported by these reserves matures in 2006. Total
proved reserves on the fields with this dedicated production were 919,265 MMcfe.

<Table>
<Caption>
                                                                   NET PROVED RESERVES(1)
                                                           --------------------------------------
                                                           NATURAL GAS    LIQUIDS(2)      TOTAL
                                                           -----------    ----------    ---------
                                                             (MMcf)        (MBbls)       (MMcfe)
<S>                                                        <C>            <C>           <C>
United States
  Producing..............................................     694,112       28,648        866,000
  Non-Producing..........................................     274,700       11,973        346,537
  Undeveloped............................................     598,827       25,859        753,980
                                                            ---------       ------      ---------
          Total proved...................................   1,567,639       66,480      1,966,517
                                                            =========       ======      =========
Canada
  Producing..............................................      89,144        4,213        114,422
  Non-Producing..........................................      14,555          233         15,953
  Undeveloped............................................      26,701        1,694         36,865
                                                            ---------       ------      ---------
          Total proved...................................     130,400        6,140        167,240
                                                            =========       ======      =========
Other Countries(3)
  Producing..............................................          --           --             --
  Non-Producing..........................................          --           --             --
  Undeveloped............................................      76,032       12,652        151,944
                                                            ---------       ------      ---------
          Total proved...................................      76,032       12,652        151,944
                                                            =========       ======      =========
Worldwide
  Producing..............................................     783,256       32,861        980,422
  Non-Producing..........................................     289,255       12,206        362,490
  Undeveloped............................................     701,560       40,205        942,789
                                                            ---------       ------      ---------
          Total proved...................................   1,774,071       85,272      2,285,701
                                                            =========       ======      =========
</Table>

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

(1)Net proved reserves exclude royalties and interests owned by others and
   reflects contractual arrangements and royalty obligations in effect at the
   time of the estimate.
(2)Includes oil, condensate and natural gas liquids.
(3)Includes international operations in Brazil, Hungary and Indonesia.

     During 2002, as a result of El Paso's efforts to enhance its liquidity
position, we sold reserves totaling 1.6 Tcfe to various third parties. The
reserves sold were primarily located in Colorado, Texas, Utah and western
Canada.

     There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures, including many factors beyond Production's 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 owned by Production declines as reserves are depleted. Except to the
extent Production conducts successful exploration and development activities or
acquires additional properties containing proved reserves, or both, the proved
reserves of Production will decline as reserves are produced. For further
discussion of our reserves, see Part II, Item 8, Financial Statements and
Supplementary Data, Note 22.

                                        6
<PAGE>

  Wells and Acreage

     The following table details Production's gross and net interest in
developed and undeveloped onshore, offshore, coal seam and international acreage
at December 31, 2002. Any acreage in which Production's 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)
                                 ---------   ---------   ----------   ---------   ----------   ---------
<S>                              <C>         <C>         <C>          <C>         <C>          <C>
United States
  Onshore......................    713,948     208,440      656,301     488,684    1,370,249     697,124
  Offshore.....................    315,688     210,795      418,926     391,988      734,614     602,783
  Coal Seam....................     27,488       7,449          160          16       27,648       7,465
                                 ---------   ---------   ----------   ---------   ----------   ---------
         Total.................  1,057,124     426,684    1,075,387     880,688    2,132,511   1,307,372
                                 ---------   ---------   ----------   ---------   ----------   ---------
International
  Australia....................         --          --    1,770,364     677,350    1,770,364     677,350
  Bolivia......................         --          --      154,840      19,355      154,840      19,355
  Brazil.......................         --          --    6,757,164   4,690,446    6,757,164   4,690,446
  Canada.......................    338,971     174,533      881,353     698,905    1,220,324     873,438
  Hungary......................         --          --      568,100     568,100      568,100     568,100
  Indonesia....................         --          --    1,213,170     378,397    1,213,170     378,397
                                 ---------   ---------   ----------   ---------   ----------   ---------
         Total.................    338,971     174,533   11,344,991   7,032,553   11,683,962   7,207,086
                                 ---------   ---------   ----------   ---------   ----------   ---------
         Worldwide Total.......  1,396,095     601,217   12,420,378   7,913,241   13,816,473   8,514,458
                                 =========   =========   ==========   =========   ==========   =========
</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.

     The U.S. domestic net developed acreage is concentrated primarily in the
Gulf of Mexico (49 percent), Utah (32 percent), and Texas (16 percent).
Approximately 34 percent, 29 percent and 19 percent of our total U.S. net
undeveloped acreage is held under leases that have minimum remaining primary
terms expiring in 2003, 2004 and 2005. During 2002, we sold approximately
345,180 net developed and 519,752 net undeveloped acres in Colorado, Texas, Utah
and western Canada as a result of El Paso's efforts to enhance its liquidity
position.

     The following table details Production's working interests in onshore,
offshore, coal seam and international natural gas and oil wells at December 31,
2002:

<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>
United States
  Onshore................     706        593       306        230       1,012        823        28          22
  Offshore...............     212        102        34         22         246        124         3           3
  Coal Seam..............     294         65        --         --         294         65        --          --
                            -----      -----       ---        ---       -----      -----        --          --
         Total...........   1,212        760       340        252       1,552      1,012        31          25
                            -----      -----       ---        ---       -----      -----        --          --
International
  Canada.................     267        170       135         77         402        247         6           5
  Other..................       1          1        --         --           1          1        --          --
                            -----      -----       ---        ---       -----      -----        --          --
         Total...........     268        171       135         77         403        248         6           5
                            =====      =====       ===        ===       =====      =====        ==          ==
         Worldwide
           Total.........   1,480        931       475        329       1,955      1,260        37          30
                            =====      =====       ===        ===       =====      =====        ==          ==
</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.

     During 2002, as a result of El Paso's efforts to enhance its liquidity
position, we sold approximately 1,680 net wells in Colorado, Texas, Utah, and
western Canada.

                                        7
<PAGE>

     The following table details Production's exploratory and development wells
drilled during the years 2000 through 2002:

<Table>
<Caption>
                                                   NET EXPLORATORY      NET DEVELOPMENT
                                                    WELLS DRILLED        WELLS DRILLED
                                                  ------------------   ------------------
                                                  2002   2001   2000   2002   2001   2000
                                                  ----   ----   ----   ----   ----   ----
<S>                                               <C>    <C>    <C>    <C>    <C>    <C>
United States
  Productive....................................    8      9     10    176    183    224
  Dry...........................................    4      3      7      5     19     14
                                                   --     --     --    ---    ---    ---
     Total......................................   12     12     17    181    202    238
                                                   --     --     --    ---    ---    ---
Canada
  Productive....................................   18     21      3      5     38     10
  Dry...........................................   27     35      3      1      3      1
                                                   --     --     --    ---    ---    ---
     Total......................................   45     56      6      6     41     11
                                                   --     --     --    ---    ---    ---
Other Countries(1)
  Productive....................................    1     --     --     --     --     --
  Dry...........................................    1      6      1     --      1     --
                                                   --     --     --    ---    ---    ---
     Total......................................    2      6      1     --      1     --
                                                   --     --     --    ---    ---    ---
Worldwide
  Productive....................................   27     30     13    181    221    234
  Dry...........................................   32     44     11      6     23     15
                                                   --     --     --    ---    ---    ---
     Total......................................   59     74     24    187    244    249
                                                   --     --     --    ---    ---    ---
</Table>

---------------
(1) Includes international operations in Australia, Brazil, Hungary and
    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.

  Net Production, Sales Prices, Transportation and Production Costs

     The following tables detail Production's net production volumes, average
sales prices received, average transportation costs, average production costs
and production taxes associated with the sale of natural gas and oil for each of
the three years ended December 31:

<Table>
<Caption>
                                                             2002      2001      2000
                                                            ------    ------    ------
<S>                                                         <C>       <C>       <C>
Net Production Volumes
  United States
     Natural Gas (Bcf)....................................     247       373       328
     Oil, Condensate and Liquids (MMBbls).................       7         8         6
       Total (Bcfe).......................................     289       422       367
Canada
     Natural Gas (Bcf)....................................      17        13         1
     Oil, Condensate and Liquids (MMBbls).................       1         1        --
       Total (Bcfe).......................................      23        17         1
Worldwide
     Natural Gas (Bcf)....................................     264       386       329
     Oil, Condensate and Liquids (MMBbls).................       8         9         6
       Total (Bcfe).......................................     312       439       368

Natural Gas Average Sales Price (per Mcf)(1)
  United States
     Price excluding hedges...............................  $ 3.15    $ 4.23    $ 3.98
     Price including hedges...............................  $ 4.22    $ 4.09    $ 2.90
  Canada
     Price excluding hedges...............................  $ 2.85    $ 2.86    $ 4.27
     Price including hedges...............................  $ 2.84    $ 2.85    $ 4.27
</Table>

                                        8
<PAGE>

<Table>
<Caption>
                                                             2002      2001      2000
                                                            ------    ------    ------
<S>                                                         <C>       <C>       <C>
  Worldwide
     Price excluding hedges...............................  $ 3.09    $ 4.18    $ 3.99
     Price including hedges...............................  $ 4.14    $ 4.05    $ 2.90
</Table>

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

(1) Prices are stated before transportation costs.

<Table>
<Caption>
                                                             2002      2001      2000
                                                            ------    ------    ------
<S>                                                         <C>       <C>       <C>

Oil, Condensate, and Liquids Average Sales Price (per
  Bbl)(1)
  United States
     Price excluding hedges...............................  $20.08    $23.10    $28.49
     Price including hedges...............................  $20.12    $23.10    $24.99
  Canada
     Price excluding hedges...............................  $21.56    $17.68    $   --
     Price including hedges...............................  $21.55    $18.52    $   --
  Worldwide
     Price excluding hedges...............................  $20.28    $22.75    $28.49
     Price including hedges...............................  $20.31    $22.81    $24.99
Average Transportation Cost (per Mcfe)
  United States
     Natural gas..........................................  $ 0.15    $ 0.06    $ 0.07
     Oil, condensate, and liquids.........................  $ 0.66    $ 0.68    $ 0.12
  Canada
     Natural gas..........................................  $ 0.19    $ 0.17    $ 0.17
     Oil, condensate, and liquids.........................  $ 0.39    $ 0.26    $   --
  Worldwide
     Natural gas..........................................  $ 0.16    $ 0.07    $ 0.07
     Oil, condensate, and liquids.........................  $ 0.62    $ 0.65    $ 0.12

Average Production Cost and Production Taxes (per Mcfe)(2)
  United States
     Average Production Cost..............................  $ 0.57    $ 0.50    $ 0.45
     Average Production Taxes.............................  $ 0.08    $ 0.16    $ 0.12
  Canada
     Average Production Cost..............................  $ 0.80    $ 0.74    $ 0.66
  Worldwide
     Average Production Cost..............................  $ 0.59    $ 0.51    $ 0.45
     Average Production Taxes.............................  $ 0.07    $ 0.16    $ 0.12
</Table>

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

(1) Prices are stated before transportation costs.

(2) Production costs include direct lifting costs (labor, repairs and
    maintenance, materials and supplies) and the administrative costs of field
    offices, insurance and property and severance taxes.

                                        9
<PAGE>

  Acquisition, Development and Exploration Expenditures

     The following table details information regarding Production's costs
incurred in its development, exploration and acquisition activities for each of
the three years ended December 31:

<Table>
<Caption>
                                                            2002      2001      2000
                                                           ------    ------    ------
                                                                 (IN MILLIONS)
<S>                                                        <C>       <C>       <C>
  United States
     Acquisition Costs:
       Proved............................................  $   23    $   87    $  127
       Unproved..........................................      12        33       130
     Development Costs...................................     717     1,026       960
     Exploration Costs:
       Delay Rentals.....................................       4         9         6
       Seismic Acquisition and Reprocessing..............       2        10        51
       Drilling..........................................      43        91       136
                                                           ------    ------    ------
          Total..........................................  $  801    $1,256    $1,410
                                                           ======    ======    ======
  Canada
     Acquisition Costs:
       Proved............................................  $    6    $  232    $    3
       Unproved..........................................       7        16         6
     Development Costs...................................      80       105        69
     Exploration Costs:
       Delay Rentals.....................................      --        --        --
       Seismic Acquisition and Reprocessing..............      21        10        10
       Drilling..........................................      49         9        32
                                                           ------    ------    ------
          Total..........................................  $  163    $  372    $  120
                                                           ======    ======    ======
  Other Countries(1)
     Acquisition Costs:
       Proved............................................  $   --    $   --    $   --
       Unproved..........................................      10        26        --
     Development Costs...................................       3        14        --
     Exploration Costs:
       Delay Rentals.....................................      --        --        --
       Seismic Acquisition and Reprocessing..............      34         6        18
       Drilling..........................................      20        61        14
                                                           ------    ------    ------
          Total..........................................  $   67    $  107    $   32
                                                           ======    ======    ======
  Worldwide
     Acquisition Costs:
       Proved............................................  $   29    $  319    $  130
       Unproved..........................................      29        75       136
     Development Costs...................................     800     1,145     1,029
     Exploration Costs:
       Delay Rentals.....................................       4         9         6
       Seismic Acquisition and Reprocessing..............      57        26        79
       Drilling..........................................     112       161       182
                                                           ------    ------    ------
          Total..........................................  $1,031    $1,735    $1,562
                                                           ======    ======    ======
</Table>

---------------------
(1) Includes international operations in Australia, Brazil, Hungary and
    Indonesia.

                                        10
<PAGE>

     The table below details approximate amounts spent to develop proved
undeveloped reserves that were included in our reserve report as of January 1 of
each year:

<Table>
<Caption>
                                                              2002   2001   2000
                                                              ----   ----   ----
Cost to Develop Proved Undeveloped Reserves                     (IN MILLIONS)
<S>                                                           <C>    <C>    <C>
United States...............................................  $216   $413   $217
Canada......................................................    11     17     24
                                                              ----   ----   ----
  Total.....................................................  $227   $430   $241
                                                              ====   ====   ====
</Table>

  Regulatory and Operating Environment

     Production's natural gas and oil activities are regulated at the federal,
state and local levels, as well as internationally by the countries around the
world in which Production does 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. Production is also
subject to governmental safety regulations in the jurisdictions in which it
operates.

     Production's 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.
Production's 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 Production's
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 behalf of Production for sudden and accidental spills and oil
pollution liability.

     Production's 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. Offshore operations may encounter usual marine perils, including
hurricanes and other adverse weather conditions, governmental regulations and
interruption or termination by governmental authorities based on environmental
and other considerations. Customary with industry practices, we maintain
insurance coverage on behalf of Production with respect to potential losses
resulting from these operating hazards.

  Markets and Competition

     Our Production segment primarily sells its natural gas to third parties
through the trading group of El Paso at spot market prices. As a result of El
Paso's plan to exit the energy trading business announced in November 2002, our
Production segment is currently evaluating how it will sell its production in
the future. Alternatives being considered include whether to cancel its
agreement with El Paso's trading group and assume responsibility for natural gas
sales to third parties or enter into new marketing agreements with third parties
engaged in the marketing of natural gas. Production sells its natural gas
liquids at market prices under monthly or long-term contracts and its oil
production at posted prices, subject to adjustments for gravity and
transportation. Production also engages in hedging activities on its natural gas
and oil production to stabilize its cash flows and reduce the risk of downward
commodity price movements on sales of its production. This is achieved primarily
through natural gas and oil swaps. Under our hedging program, we may hedge up to
50 percent of our anticipated production for a rolling 12-month forward period.

     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. Production's competitors include major and intermediate
sized natural gas and oil companies, independent natural gas and oil operations
and individual producers or operators with varying scopes of operations and
financial resources. Competitive factors include

                                        11
<PAGE>

price, contract terms and quality of service. 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.

                             FIELD SERVICES SEGMENT

     Our Field Services segment provides customers with wellhead-to-mainline
services, including natural gas gathering, products extraction, fractionation,
dehydration, purification, compression and transportation of natural gas and
NGL. It also provides well-ties and real-time information services, including
electronic wellhead gas flow measurement.

     Field Services' assets include natural gas gathering and NGL pipelines,
treating, processing and fractionation facilities, in the south Texas, south
Louisiana, Mid-Continent and Rocky Mountain regions.

     In May 2002, we sold our Dragon Trail processing plant and in November
2002, we sold our 14.4 percent interest in the Aux Sable NGL plant. In December
2002, we sold our Natural Buttes and Ouray gas gathering facilities which
included 250 miles of natural gas gathering pipelines with approximately 200
MMcf/d of capacity. These assets gathered 146 BBtu/d for the year ended December
31, 2002. Also in December 2002, we sold our 50 percent interest in the Blacks
Fork Gas Processing Company which owns the Blacks Fork natural gas processing
plant in Wyoming. In January 2003, we sold several of our small gathering
systems located in Wyoming, which included 500 miles of natural gas gathering
pipelines with a capacity of 325 MMcf/d. These assets gathered 145 BBtu/d for
the year ended December 31, 2002. In March 2003, we received approval to sell
our remaining assets in the Mid-Continent region. These assets primarily include
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. We expect this sale to close by the end of
2003.

     The following tables provide information on Field Services' natural gas
gathering and transportation facilities, its processing facilities and the
facilities of its equity method investees:

<Table>
<Caption>
                                            AS OF DECEMBER 31, 2002
                                           -------------------------     AVERAGE THROUGHPUT
                                            MILES OF     THROUGHPUT     --------------------
          GATHERING & TREATING              PIPELINE      CAPACITY      2002    2001    2000
          --------------------             -----------   -----------    ----    ----    ----
                                                          (MMcfe/d)          (BBtue/d)
<S>                                        <C>           <C>            <C>     <C>     <C>
Field Services...........................     3,816        1,141        628     843     874
</Table>

<Table>
<Caption>
                              AS OF                                     AVERAGE NATURAL GAS
                        DECEMBER 31, 2002     AVERAGE INLET VOLUME         LIQUIDS SALES
                        -----------------   ------------------------   ---------------------
  PROCESSING PLANTS      INLET CAPACITY     2002      2001      2000   2002    2001    2000
  -----------------     -----------------   -----   ---------   ----   -----   -----   -----
                            (MMcfe/d)              (BBtue/d)                 (Mgal/d)
<S>                     <C>                 <C>     <C>         <C>    <C>     <C>     <C>
Field Services........        2,889         1,754     1,966     1,910  2,139   2,595   2,409
</Table>

  Regulatory Environment

     We are subject to the Natural Gas Pipeline Safety Act of 1968, the
Hazardous Liquid Pipeline Safety Act 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

     Field Services competes with major interstate and intrastate pipeline
companies in transporting natural gas and NGL. Field Services also competes 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. 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.

                                        12
<PAGE>

                            MERCHANT ENERGY SEGMENT

     Our Merchant Energy segment consists of two primary divisions: global power
and petroleum.

Global Power

     Our global power division includes the ownership and operation of domestic
and international power generation facilities. We own or have interests in 19
power plants in 8 countries. These plants represent 4,378 gross megawatts of
generating capacity, 87 percent of which is sold under power purchase or tolling
agreements with terms in excess of five years. Of these facilities, 37 percent
are natural gas fired and 63 percent are a combination of coal, NGL and other
fuels. Internationally, our focus is on building and acquiring energy
infrastructure in developed economies, and to a lesser degree in selected
emerging markets. Our primary international areas of focus historically have
included Asia and Central America.

     Detailed below are our generating capacity by power facility for our power
plants as of December 31, 2002:

<Table>
<Caption>
                                                                 GROSS         OWNERSHIP
PROJECT                                                       MEGAWATTS(1)     INTEREST
-------                                                       ------------     ---------
                                                                               (PERCENT)
<S>                                                           <C>              <C>
Bastrop Company, LLC.......................................        534            50
CDECCA.....................................................         62            50
Eagle Point Cogeneration Partnership.......................        233            84
EGE Fortuna................................................        300            25
EGE Itabo..................................................        513            25
Habibullah Power...........................................        136            50
Midland Cogeneration Venture...............................      1,575            44
Nejapa Power...............................................        144            87
Saba Power Company.........................................        128            93
Other projects.............................................        753         various
                                                                 -----
          Total............................................      4,378
                                                                 =====
</Table>

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

(1) Gross megawatts represent the tested generating capacity of these
    facilities.

     Detailed below are our power generation projects, by region as of December
31, 2002:

<Table>
<Caption>
                                                          NUMBER OF       GROSS           NET
REGION                            PROJECT STATUS          FACILITIES   MEGAWATTS(1)   MEGAWATTS(2)
------                            --------------          ----------   ------------   ------------
<S>                       <C>                             <C>          <C>            <C>
United States
  East Coast              Operational...................       4            429            429
  Central                 Operational...................       2          2,109            952
Asia                      Operational...................       6            600            419
Central America           Operational...................       6          1,190            419
                          Under Construction............       1             50             11
                                                              --          -----          -----
          Total.........................................      19          4,378          2,230
                                                              ==          =====          =====
</Table>

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

(1) Gross megawatts represent the tested generating capacity of these
    facilities.
(2) Net megawatts represent our net ownership in the facilities.

Petroleum

     In February 2003, El Paso announced its intent to sell substantially all of
our petroleum business (with the exception of our Aruba refinery) since it is
not core to our primary natural gas business.

                                        13
<PAGE>

     Our existing petroleum division: (i) owns or has interests in four crude
oil refineries and five chemical production facilities; (ii) has petroleum
terminalling and related marketing operations; and (iii) has blending and
packaging operations that produce and distribute a variety of lubricants and
automotive related products. Of the four refineries we own, we operate three of
them. The three refineries we operate have a throughput capability of
approximately 438 MBbls of crude oil per day to produce a variety of gasolines,
diesel fuels, asphalt, industrial fuels and other products. Our chemical
facilities have a production capability of 3,800 tons per day and produce
various industrial and agricultural products.

     In 2002, our refineries operated at 64 percent of their average combined
capacity, at 70 percent in 2001 and at 93 percent in 2000. The aggregate sales
volumes at our wholly owned refineries were approximately 110 MMBbls in 2002,
131 MMBbls in 2001 and 182 MMBbls in 2000. Of our total refinery sales in 2002,
38 percent was gasoline, 41 percent was middle distillates, such as jet fuel,
diesel fuel and home heating oil, and 21 percent was heavy industrial fuels and
other products.

     The following table presents average daily throughput and storage capacity
at our wholly owned refineries at December 31:

<Table>
<Caption>
                                                         AVERAGE           AT DECEMBER 31,
                                                          DAILY                 2002
                                                        THROUGHPUT       -------------------
                                                    ------------------    DAILY     STORAGE
REFINERY                      LOCATION              2002   2001   2000   CAPACITY   CAPACITY
--------                      --------              ----   ----   ----   --------   --------
                                                                   (IN MBBLS)
<S>                <C>                              <C>    <C>    <C>    <C>        <C>
Aruba              Aruba..........................  146    178    229      280       15,320
Eagle Point        Westville, New Jersey..........  127    118    143      140        8,492
Corpus Christi(1)  Corpus Christi, Texas..........   --     38     99       --           --
Mobile             Mobile, Alabama................    9     10     12       18          600
                                                    ---    ---    ---      ---       ------
     Total........................................  282    344    483      438       24,412
                                                    ===    ===    ===      ===       ======
</Table>

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

(1) In June 2001, we leased our Corpus Christi refinery to Valero Energy
    Corporation for 20 years. In February 2003, Valero exercised its option to
    purchase the plant and related assets. These volumes only reflect those
    produced prior to our lease of the facilities.

     Our chemical plants produce agricultural fertilizers, gasoline additives
and other industrial products from facilities in Nevada, Oregon and Wyoming. The
following table presents sales volumes from our wholly owned chemical facilities
in the U.S. for each of the three years ended December 31:

<Table>
<Caption>
                                                              2002    2001    2000
                                                              -----   -----   -----
                                                                     (MTONS)
<S>                                                           <C>     <C>     <C>
Industrial..................................................    512     492     547
Agricultural................................................    380     378     389
Gasoline additives..........................................    199     173     214
                                                              -----   -----   -----
          Total.............................................  1,091   1,043   1,150
                                                              =====   =====   =====
</Table>

     Since January 2003, we have sold the majority of our interests in our
Florida petroleum terminals, our tug and barge operations, and all of our
interests in the Corpus Christi refinery. We also announced the sale of our
leasehold crude business and asphalt operations. We expect to sell the rest of
the assets associated with our petroleum business in 2003, with the exception of
the Aruba refinery.

 Regulatory Environment

     Merchant Energy's domestic power generation activities are regulated by the
FERC under the Federal Power Act with respect to its rates, terms and conditions
of service. In addition, exports of electricity outside of the U.S. must be
approved by the Department of Energy. Merchant Energy's cogeneration power
production activities are regulated by the FERC under the Public Utility
Regulatory Policies Act (PURPA) with respect to rates, procurement and provision
of services and operating standards. Its power generation and refining, chemical
and petroleum activities are also subject to federal, state and local
environmental regulations. We believe that our operations are in material
compliance with the applicable requirements.

                                        14
<PAGE>

     Merchant Energy's foreign operations are regulated by numerous governmental
agencies in the countries in which these projects are located. Many of the
countries in which Merchant Energy conducts and will 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 and sometimes limited. Many detailed rules and procedures are
yet to be issued, and we expect that the interpretation of existing rules in
these jurisdictions will evolve over time. We believe that our operations are in
material compliance with all environmental laws and regulations in the
applicable foreign jurisdictions.

  Markets and Competition

     During 2002, Merchant Energy's activities served over 1,400 suppliers and
2,900 customers around the world. Merchant Energy's businesses operate in a
highly competitive environment. Its primary competitors include:

     - affiliates of major oil and natural gas producers;

     - multi-national energy infrastructure companies;

     - large domestic and foreign utility companies;

     - affiliates of large local distribution companies;

     - affiliates of other interstate and intrastate pipelines;

     - independent energy marketers and power producers with varying scopes of
       operations and financial resources; and

     - independent refining and chemical companies.

     Merchant Energy competes on the basis of price, operating efficiency,
technological advances, experience in the marketplace and counterparty credit.
Each market served by Merchant Energy is influenced directly or indirectly by
energy market economics.

     Many of Merchant Energy's power generation facilities sell power pursuant
to long-term agreements with investor-owned utilities in the U.S. The terms of
its power purchase agreements for its facilities are such that Merchant Energy's
revenues from these facilities are not significantly impacted by competition
from other sources of generation. The power generation industry is rapidly
evolving and regulatory initiatives have been adopted at the federal and state
level aimed at increasing competition in the power generation business. As a
result, it is likely that when the power purchase agreements expire, these
facilities will be required to compete in a significantly different market in
which operating efficiency and other economic factors will determine success.
Merchant Energy is likely to face intense competition from generation companies
as well as from the wholesale power markets.

                                 ENVIRONMENTAL

     A description of our environmental activities is included in Part II, Item
8, Financial Statements and Supplementary Data, Note 16, and is incorporated
herein by reference.

                                   EMPLOYEES

     As of March 26, 2003, we had approximately 3,060 full-time employees, of
which 532 are subject to collective bargaining agreements.

                                        15
<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 is included in Part II, Item 8,
Financial Statements and Supplementary Data, Note 16, and is incorporated herein
by reference.

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

     Item 4, Submission of Matters to a Vote of Security Holders, has been
omitted from this report pursuant to the reduced disclosure format permitted by
General Instruction I to Form 10-K.

                                    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, there is no public trading market for our common stock.

ITEM 6. SELECTED FINANCIAL DATA

     Item 6, Selected Financial Data, has been omitted from this report pursuant
to the reduced disclosure format permitted by General Instruction I to Form
10-K.

                                        16
<PAGE>

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

     The information required by this Item is presented in a reduced disclosure
format permitted by General Instruction I to Form 10-K. The Notes to
Consolidated Financial Statements contain information that is pertinent to the
following analysis, including a discussion of our significant accounting
policies.

                             RESULTS OF OPERATIONS

     We use earnings before interest and income taxes (EBIT) to assess the
operating results and effectiveness of our business segments. We define EBIT as
operating income, adjusted for earnings from unconsolidated affiliates and other
miscellaneous non-operating items. Items that are not included in this measure
are financing costs, including interest and debt expense, income taxes,
discontinued operations, extraordinary items and cumulative effect of accounting
changes. The following is a reconciliation of our operating results to EBIT and
loss from continuing operations for the years ended December 31:

<Table>
<Caption>
                                                               2002      2001
                                                              -------   -------
                                                                (IN MILLIONS)
<S>                                                           <C>       <C>
Operating revenues..........................................  $ 8,530   $ 8,724
Operating expenses..........................................   (8,394)   (8,666)
                                                              -------   -------
  Operating income..........................................      136        58
Earnings from unconsolidated affiliates.....................      104       233
Minority interest in consolidated subsidiaries..............      (52)       --
Other income................................................      118       190
Other expenses..............................................      (37)      (28)
                                                              -------   -------
  EBIT......................................................      269       453
Interest and debt expense...................................     (433)     (447)
Affiliated interest expense, net............................       (9)      (46)
Returns on preferred interests of consolidated
  subsidiaries..............................................      (35)      (51)
Income taxes................................................       35       (81)
                                                              -------   -------
  Loss from continuing operations...........................  $  (173)  $  (172)
                                                              =======   =======
</Table>

     We believe EBIT is a useful measurement for our investors because it
provides information that can be used to evaluate the effectiveness of our
businesses and investments from an operational perspective, exclusive of the
costs to finance those activities and exclusive of income taxes, neither of
which are directly relevant to the efficiency of those operations. This
measurement may not be comparable to measurements used by other companies and
should not be used as a substitute for net income or other performance measures
such as operating cash flow.

                                        17
<PAGE>

OVERVIEW OF RESULTS OF OPERATIONS

     Below are our results of operations (as measured by EBIT), by segment for
the years ended December 31, 2002 and 2001. These results include the impacts of
restructuring and merger-related costs, asset impairments, other charges, and
gains (losses) on long-lived assets, which are discussed further in Item 8,
Financial Statements and Supplementary Data, Notes 3, 4 and 20. See Item 8,
Financial Statements and Supplementary Data, Note 18, for a reconciliation of
our operating results to EBIT by segment.

<Table>
<Caption>
EBIT BY SEGMENT                                               2002    2001
---------------                                               ----   ------
                                                              (IN MILLIONS)
<S>                                                           <C>    <C>
Pipelines...................................................  $537   $  292
Production..................................................  (456)     791
Field Services..............................................    13       71
Merchant Energy.............................................   193       (3)
                                                              ----   ------
  Segment EBIT..............................................   287    1,151
Corporate and other.........................................   (18)    (698)
                                                              ----   ------
  Consolidated EBIT from continuing operations..............  $269   $  453
                                                              ====   ======
</Table>

SEGMENT RESULTS

     Our four segments: Pipelines, Production, Field Services and Merchant
Energy are strategic business units that offer a variety of different energy
products and services, each requires different technology and marketing
strategies. Below is a discussion and analysis of the operating results of each
of our business segments. These results include the impact of the restructuring
and merger-related costs, asset impairments and other charges discussed above
for all years presented.

PIPELINES

     Our Pipelines segment consists of interstate natural gas transmission,
storage, gathering and related services in the U.S. and internationally. Our
interstate natural gas transportation systems face varying degrees of
competition from other pipelines, as well as from alternate energy sources used
to generate electricity, such as hydroelectric power, nuclear, coal and fuel
oil.

     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, and include a return on our invested capital. As a result, our
financial results 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
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.

                                        18
<PAGE>

     In November 2002, we sold 12.3 percent of our 14.4 percent equity interest
in the Alliance pipeline system, and net proceeds were $141 million. We
completed the sale of our remaining equity interest in Alliance during the first
quarter of 2003. Income earned on our investment in Alliance for the year ended
December 31, 2002 and 2001, was approximately $21 million and $23 million.

     Results of operations of the Pipelines segment were as follows for the
years ended December 31:

PIPELINE SEGMENT RESULTS

<Table>
<Caption>
                                                                2002         2001
                                                              --------     --------
                                                              (IN MILLIONS, EXCEPT
                                                                 VOLUME AMOUNTS)
<S>                                                           <C>          <C>
Operating revenues..........................................   $  926       $1,054
Operating expenses..........................................     (507)        (859)
                                                               ------       ------
  Operating income..........................................      419          195
Other income................................................      118           97
                                                               ------       ------
  EBIT......................................................   $  537       $  292
                                                               ======       ======
Throughput volumes (BBtu/d)(1)..............................    7,716        7,443
                                                               ======       ======
</Table>

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

(1) Throughput volumes exclude those related to pipeline systems sold in
    connection with Federal Trade Commission orders related to our merger with
    El Paso including the Empire State and Iroquois pipeline investments.
    Throughput volumes exclude intrasegment activities.

     Operating revenues for the year ended December 31, 2002, were $128 million
lower than in 2001. This decrease was due to a $49 million decrease from natural
gas sales, gathering and processing activities due to CIG's sale of the
Panhandle field and other production properties in July 2002, a $33 million
decrease due to reduced natural gas and liquids sales due to lower prices in
2002, and a $28 million decrease in sale of excess natural gas in 2001. Also
contributing to the decrease were $22 million lower transportation revenues due
to milder weather in 2002, $19 million from lower resales of natural gas
purchased from the Dakota gasification facility and $6 million lower 2002 sales
of base gas from abandoned storage fields. These decreases were partially offset
by higher reservation revenues of $30 million primarily due to system expansion
projects placed in service in 2001.

     Operating expenses for the year ended December 31, 2002, were $352 million
lower than in 2001 primarily as a result of merger-related costs of $192 million
incurred in 2001 to relocate our ANR pipeline operations from Detroit, Michigan
to Houston, Texas, costs for employee benefits, severance retention, transition
charges and other miscellaneous charges. Also contributing to the decrease were
$24 million from lower gas costs for our system supply purchases resulting from
lower natural gas prices and volumes, $27 million from lower benefit costs and
cost efficiencies following our merger with El Paso, $19 million from lower
prices on gas purchases from the Dakota gasification facility, $18 million from
lower amortization of goodwill due to the implementation of SFAS No. 142 in
2002, a $22 million decrease in operating expenses due to CIG's sale of
Panhandle field and other production properties in July 2002, $11 million due to
a gain on the sale of pipeline expansion rights in February 2002, and $5 million
lower corporate overhead allocations.

     Other income for the year ended December 31, 2002, was $21 million higher
than in 2001. The increase was due to the resolution of uncertainties associated
with the sales of our interests in the Empire State, Iroquois pipeline systems,
and our Gulfstream pipeline project in 2001 of $11 million and higher equity
earnings in 2002 of $8 million on our Great Lakes Gas Transmission investment.
These increases were partially offset by lower equity earnings of $6 million on
Empire State and Iroquois pipeline systems due to the sale of our interests in
2001.

PRODUCTION

     The 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

                                        19
<PAGE>

gas and oil reserves, extract those reserves with minimal production costs, sell
the products at attractive prices and operate at the lowest total cost level
possible.

     Production has historically engaged in hedging activities on its natural
gas and oil production to stabilize cash flows and to reduce the risk of
downward commodity price movements on its production. This is achieved primarily
through natural gas and oil swaps. In the past, our stated goal was to hedge
approximately 75 percent of our anticipated current year production,
approximately 50 percent of our anticipated succeeding year production and a
lesser percentage thereafter. In May 2002, we modified this hedging strategy.
Under the modified strategy, we may hedge up to 50 percent of our anticipated
production for a rolling 12-month forward period. This modification of our
hedging strategy will increase our exposure to changes in commodity prices which
could result in significant volatility in our reported results of operations,
financial position and cash flows from period to period. As of December 31,
2002, we have hedged approximately 83 million MMBtu's of our anticipated natural
gas production for 2003 at a NYMEX Henry Hub price of $4.36 per MMBtu before
regional price differentials and transportation costs.

     During 2002, we continued an active onshore and offshore development
drilling program to capitalize on our land and seismic holdings. This
development drilling was done to take advantage of our large inventory of
drilling prospects and to develop our proved undeveloped reserve base. We also
completed asset dispositions in Colorado, Utah, western Canada and Texas as part
of El Paso's liquidity enhancement plan. Primarily due to our asset
dispositions, we have a lower reserve base at January 1, 2003 than we did at
January 1, 2002. See Item 8, Financial Statements and Supplementary Data, Note
22, for a discussion of our natural gas and oil reserves. Since our depletion
rate is determined under the full cost method of accounting, a lower reserve
base coupled with additional capital expenditures in the full cost pool will
result in a higher depletion rate in future periods. For the first quarter of
2003, we expect our domestic unit of production depletion rate to be
approximately $1.87 per Mcfe.

     We currently expect to reduce our total capital expenditures from
approximately $1.1 billion in 2002 to approximately $600 million in 2003. We
continually evaluate our capital expenditure program and this estimate 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.

     Below are the operating results and analysis of these results for the years
ended December 31:

<Table>
<Caption>
                 PRODUCTION SEGMENT RESULTS                     2002        2001
                 --------------------------                   ---------   ---------
                                                              (IN MILLIONS, EXCEPT
                                                               VOLUMES AND PRICES)
<S>                                                           <C>         <C>
Operating Revenues:
Natural gas.................................................  $  1,091    $  1,562
Oil, condensate and liquids.................................       162         200
Other.......................................................         5          21
                                                              --------    --------
          Total operating revenues..........................     1,258       1,783
Transportation and net product costs........................       (52)        (56)
                                                              --------    --------
          Total operating margin............................     1,206       1,727
Operating expenses(1).......................................    (1,667)       (942)
                                                              --------    --------
  Operating income (loss)...................................      (461)        785
Other income................................................         5           6
                                                              --------    --------
  EBIT......................................................  $   (456)   $    791
                                                              ========    ========
</Table>

---------------------
(1) Includes production costs, depletion, depreciation and amortization, ceiling
    test charges, merger related costs, gains (losses) on long-lived assets,
    changes in accounting estimates, corporate overhead, general and
    administrative expenses and severance and other taxes.

                                        20
<PAGE>

<Table>
<Caption>
                                                                2002        2001
                                                              ---------   ---------
                                                              (IN MILLIONS, EXCEPT
                                                               VOLUMES AND PRICES)
<S>                                                           <C>         <C>
Volumes and Prices:
  Natural gas
     Volumes (MMcf).........................................   263,749     385,793
                                                              ========    ========
     Average realized prices with hedges ($/Mcf)(1).........  $   4.14    $   4.05
                                                              ========    ========
     Average realized prices without hedges ($/Mcf)(1)......  $   3.09    $   4.18
                                                              ========    ========
     Average transportation costs ($/Mcf)...................  $   0.16    $   0.07
                                                              ========    ========
  Oil, condensate and liquids
     Volumes (MBbls)........................................     7,981       8,787
                                                              ========    ========
     Average realized prices with hedges ($/Bbl)(1).........  $  20.31    $  22.81
                                                              ========    ========
     Average realized prices without hedges ($/Bbl)(1)......  $  20.28    $  22.75
                                                              ========    ========
     Average transportation costs ($/Bbl)...................  $   0.62    $   0.65
                                                              ========    ========
</Table>

---------------------
(1) Prices are stated before transportation costs.

     For the year ended December 31, 2002, operating revenues were $525 million
lower than in 2001. A 32 percent decrease in natural gas volumes and a 26
percent decrease in natural gas prices before hedges and transportation costs
account for $799 million of the decrease in revenues, offset by a $326 million
favorable variance from natural gas hedging activity in 2002 when compared to
2001. The decline in natural gas volumes is primarily attributed to the sale of
properties in Colorado, Utah and Texas. A nine percent decrease in oil,
condensate and liquids volumes and an 11 percent decrease in their prices before
hedges and transportation costs resulted in a $38 million decrease in revenues.

     Transportation and net product costs for the year ended December 31, 2002,
were $4 million lower than in 2001 primarily due to a lower percentage of gas
volumes subject to transportation fees, offset by higher costs incurred to meet
minimum payments on pipeline agreements.

     Operating expenses for the year ended December 31, 2002, were $725 million
higher than in 2001 primarily due to a $702 million loss recognized in December
2002 on the sale of our natural gas and oil properties in Utah. A loss was
recognized on this sale because the reserves sold significantly altered the
relationship between capitalized costs and proved reserves. Also contributing to
the increase in expenses were non-cash full cost ceiling test charges totaling
$245 million incurred in 2002 for our Canadian full cost pool and other
international properties, primarily in Brazil and Australia, offset by 2001
non-cash full cost ceiling test charges on international properties totaling
$115 million. Also contributing to the increase in 2002 expenses were a $4
million charge for a Canadian intangible asset impairment, and a higher
corporate overhead allocation of $43 million partially offset by decreased
oilfield service costs of $31 million. Partially offsetting the increase in
expenses was the unit of production depletion expense which was lower by $9
million with $128 million resulting from lower production volumes in 2002 offset
by $119 million due to higher depletion rates in 2002. The higher depletion rate
resulted from higher capitalized costs in the full cost pool and a lower reserve
base. Further offsetting the increase in expenses were merger related costs of
$45 million and asset impairments of $16 million incurred in 2001 related to our
combined operations with El Paso and $10 million for write-downs of materials
and supplies recognized in 2001 resulting from the reduction in inventory values
due to the implementation of consistent operating standards, strategies and
plans following the merger with El Paso. For a discussion of merger-related
costs, gains and losses on long-lived assets and changes in accounting
estimates, see Item 8, Financial Statements and Supplementary Data, Notes 3, 4
and 5. In addition, the increase in expense was offset by $46 million of lower
severance and other taxes in 2002. The severance taxes decreased primarily
because of lower natural gas volumes and prices, and for credits taken in 2002
for qualified natural gas wells.

                                        21
<PAGE>

FIELD SERVICES

     Our Field Services segment provides a variety of midstream services,
including gathering and transportation of natural gas, processing and
fractionation of natural gas, NGL and natural gas derivative products, such as
butane, ethane and propane.

     During 2002, we identified midstream assets to be sold to third parties as
part of El Paso's plan to strengthen its capital structure and enhance its
liquidity. See Item 8, Financial Statements and Supplementary Data, Note 2 for
further discussion of asset sales completed in 2002.

     In May 2002, we sold our Dragon Trail processing plant and in November
2002, we sold our 14.4 percent interest in the Aux Sable NGL plant. In December
2002, we sold our Natural Buttes and Ouray gas gathering facilities. Also in
December 2002, we sold our 50 percent interest in the Blacks Fork Gas Processing
Company which owns the Blacks Fork natural gas processing plant in Wyoming. In
January 2003, we sold several of our small gathering systems located in Wyoming.
In March 2003, we received approval to sell our assets in the Mid-Continent
region. These assets primarily include 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. We expect
this sale to close by the end of 2003. After this sale is completed, our
remaining assets will consist primarily of processing facilities in the south
Texas, south Louisiana and Rocky Mountain regions.

     As a result of our asset sales and the resulting decline in our gathering
and treating activities, we expect our future EBIT to decrease considerably.

     We attempt to balance our earnings from our operating activities through a
combination of fixed-fee based and market-based services. A majority of our
gathering and transportation operations earn margins from fixed-fee-based
services. However, some of our 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.

     Processing and fractionation 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 processing or fractionation service. 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.

     Our operating results and an analysis of those results are as follows for
years ended December 31:

<Table>
<Caption>
               FIELD SERVICES SEGMENT RESULTS                   2002         2001
               ------------------------------                 --------     --------
                                                              (IN MILLIONS, EXCEPT
                                                               VOLUMES AND PRICES)
<S>                                                           <C>          <C>
Gathering, treating and processing gross margins............   $  112       $  155
Operating expenses..........................................      (45)        (100)
                                                               ------       ------
Operating income............................................       67           55
Other income (expense)......................................      (54)          16
                                                               ------       ------
  EBIT......................................................   $   13       $   71
                                                               ======       ======
Volumes and prices
  Gathering and treating
     Volumes (BBtu/d).......................................      628          843
                                                               ======       ======
     Prices ($/MMBtu).......................................   $ 0.13       $ 0.14
                                                               ======       ======
  Processing
     Volumes (inlet BBtu/d).................................    1,754        1,966
                                                               ======       ======
     Prices ($/MMBtu).......................................   $ 0.12       $ 0.14
                                                               ======       ======
</Table>

                                        22
<PAGE>

     Total gross margins for the year ended December 31, 2002, were $43 million
lower than in 2001. Margins decreased by approximately $37 million primarily due
to lower 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 approximately $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 gains in 2002 on the sales of our
Natural Buttes and Ouray natural gas gathering systems and our Dragon Trail
processing plant of $26 million and $10 million, a decrease in 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 operating
and maintenance expenses as a result of the sale of our Dragon Trail processing
plant and our cost reduction plan in 2002. The decrease in operating expense was
partially offset by a $14 million loss associated with our write-down of
goodwill related to our SFAS No. 142 goodwill procedures.

     Other income for the year ended December 31, 2002, was $70 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 interest to El
Paso Energy Partners, an affiliate, in October 2001.

MERCHANT ENERGY

     Our Merchant Energy segment consists of two primary divisions: global power
and petroleum. Early in 2003, El Paso announced its intent to exit substantially
all of our petroleum activities (excluding our Aruba refinery).

     Below are Merchant Energy's operating results and an analysis of those
results for the years ended December 31:

<Table>
<Caption>
                                                                DIVISION                          TOTAL
                                          ----------------------------------------------------   MERCHANT
                                                                       OTHER                      ENERGY
                                          GLOBAL POWER   PETROLEUM   ACTIVITIES   ELIMINATIONS   SEGMENT
                                          ------------   ---------   ----------   ------------   --------
MERCHANT ENERGY SEGMENT RESULTS                                    (IN MILLIONS)
<S>                                       <C>            <C>         <C>          <C>            <C>
2002
Gross margin............................     $ 678        $   546       $(12)         $(14)      $ 1,198
Operating expenses......................      (190)          (872)        --            14        (1,048)
                                             -----        -------       ----          ----       -------
     Operating income (loss)............       488           (326)       (12)           --           150
Other income (expense)..................       (72)           110          5            --            43
                                             -----        -------       ----          ----       -------
  EBIT..................................     $ 416        $  (216)      $ (7)         $ --       $   193
                                             =====        =======       ====          ====       =======
2001
Gross margin............................     $  38        $   806       $  4          $ --       $   848
Operating expenses......................       (57)        (1,028)       (26)           --        (1,111)
                                             -----        -------       ----          ----       -------
     Operating loss.....................       (19)          (222)       (22)           --          (263)
Other income............................       141            112          7            --           260
                                             -----        -------       ----          ----       -------
  EBIT..................................     $ 122        $  (110)      $(15)         $ --       $    (3)
                                             =====        =======       ====          ====       =======
</Table>

  GLOBAL POWER

     Our global power division includes the ownership and operation of domestic
and international power generating facilities. In most cases, we partially own
our power generating facilities and account for them using the equity method.

                                        23
<PAGE>

     Power Contract Restructuring Activities.  Many of our domestic power plants
have long-term power sales contracts with regulated utilities that were entered
into under the Public Utility Regulatory Policies Act of 1978 (PURPA). The power
sold to the utility under these PURPA contracts is required to be delivered from
a specified power generation plant at power prices that are usually
significantly higher than the cost of power in the wholesale power market. Our
cost of generating power at these PURPA power plants is typically higher than
the cost we would incur by obtaining the power in the wholesale power market,
principally because the PURPA power plants are less efficient than newer power
generation facilities.

     Typically, in a power contract restructuring, the PURPA power sales
contract is amended so that the power sold to the utility does not have to be
provided from the specific power plant. Because we have been able to buy lower
cost power in the wholesale power market, we have the ability to reduce the cost
paid by the utility, thereby inducing the utility to enter into the power
contract restructuring transaction. Following a contract restructuring, the
power plant operates on a merchant basis, which means that it is no longer
dedicated to one buyer and will operate only when power prices are high enough
to make its operation economical. In addition, we or our affiliates, may assume,
and in the case of our Eagle Point Cogeneration facility, our affiliate, did
assume, the business and economic risks of supplying power to the utility to
satisfy the delivery requirements under the restructured power contract over its
term. When this risk is assumed, its risk is managed by entering into
transactions to buy power from third parties over the life of the contract.
Power contract restructurings generally result in a higher return in our power
generation business because we can deliver reliable power at lower prices than
our cost to generate power at these PURPA power plants. In addition, we can use
the restructured contracts as collateral to obtain financing at a cost that is
comparable to, or lower than, our existing financing costs.

     During 2002, we completed restructurings of several long-term power
contracts held by our unconsolidated affiliates or, in some cases, held by us.
As a result of our credit downgrades, El Paso's decision to exit its trading
business and disruption in the capital markets, it is unlikely we will pursue
additional power contract restructurings in the near term. For a further
discussion of these activities, see Item 8, Financial Statements and
Supplementary Data, Note 11.

GLOBAL POWER DIVISION RESULTS

<Table>
<Caption>
                                                               2002    2001
                                                              ------   -----
                                                              (IN MILLIONS)
<S>                                                           <C>      <C>
Gross margin................................................  $ 678    $ 38
Operating expenses..........................................   (190)    (57)
                                                              -----    ----
     Operating income (loss)................................    488     (19)
Other income (expense)......................................    (72)    141
                                                              -----    ----
  EBIT......................................................  $ 416    $122
                                                              =====    ====
</Table>

     Gross margins consist of revenues from our power plants and the net results
from our power restructuring activities. The cost of fuel used in the power
generation process is included in operating expenses. For the year ended
December 31, 2002, gross margin for the global power division was $640 million
higher than in 2001. Gross margin from power contract restructurings comprised
$486 million of the increase. During 2002, we completed power contract
restructurings or contract terminations at our Eagle Point Cogeneration and
Nejapa power plants. The Eagle Point restructuring transaction, completed in
March 2002, was our most significant power contract restructuring transaction
and contributed $359 million to our net 2002 results.

     The Eagle Point restructuring involved several steps and all revenues,
expenses, fees and impairments related to the transaction were reported in our
2002 gross margin. First, we amended the existing PURPA power sales contract
with Public Service Electric and Gas (PSEG) to eliminate the requirement that
power be delivered specifically from the Eagle Point power plant. This amended
contract has fixed prices with stated increases over the 14-year term that range
from $85 per MWh to $126 per MWh. We entered into the amended power sales
contract through a consolidated subsidiary, UCF. UCF was created to hold and
execute the terms of the restructured power sales contract, to enter into a
supply contract to meet the requirements of

                                        24
<PAGE>

the restructured agreement and to monetize the net cash flows of these contracts
by issuing debt. In keeping with its purpose, UCF entered into a power supply
agreement with El Paso's energy trading division (EPME) who usually participates
in our power restructuring activities by taking on the obligation to supply
power. The terms of the EPME power supply contract were identical to the amended
restructured power sales contract, with the exception of price, which was set at
$37 per MWh over its 14-year term.

     For credit enhancement purposes, in anticipation of the financing
transaction associated with the restructuring, UCF terminated the EPME supply
contract in the second quarter of 2002 and replaced it with a supply contract
with a Morgan Stanley affiliate. UCF entered into the Morgan Stanley contract
solely for the purpose of reducing the cost of debt UCF would issue.

     The actions taken to restructure the contract required us to mark the
contract to its fair value. As a result, we recorded non-cash revenue
representing the estimated fair value of the derivative contracts of
approximately $898 million. We also amended or terminated other ancillary
agreements associated with the cogeneration facility, such as gas supply and
transportation agreements, a steam contract and existing financing agreements.
We also paid $103 million to the utility to terminate the original PURPA
contract. Also included in our operating results for 2002 were a $98 million
non-cash charge to adjust the Eagle Point Cogeneration plant to fair value based
on its new status as a peaking merchant plant and a non-cash charge of $230
million to write off the book value of the original PURPA contract. The
transaction included closing and other costs of $58 million and the minority
interest owner's share of this transaction of $50 million. Total operating cash
flows from this transaction amounted to approximately $161 million of cash paid
to the utility to amend the original contract and other costs and total
financing cash flows included $829 million of proceeds from the issuance of
7.944% senior notes collateralized solely by the contracts and cash flows of
UCF.

     We also employed the principles of our power restructuring business in
contract termination at our Nejapa power plant in 2002. In 2002, an arbitration
award panel approved the termination of the power purchase agreement between
Comision Ejecutiva Hydrolectrica del Rio Lempa and the Nejapa Power Company, one
of our consolidated subsidiaries, in exchange for a cash payment of $90 million.
We recorded, as gross margin, a $90 million gain and also recorded $13 million
in other expense for the minority owner's share of this gain. We applied the
proceeds of the award to retire a portion of Nejapa's debt.

     Due to increasing market power prices in 2002, the net increase in gross
margin of $486 million from our initial power restructuring transactions was
partially offset by a decrease in the fair value of our restructured power
contract and related power supply contracts of $34 million from the initial
gains through December 31, 2002. In addition to the net increase in gross margin
relating to restructuring activities discussed above, gross margin increases of
$139 million were realized from domestic and international power facilities that
were consolidated in the fourth quarter of 2001 and the first quarter of 2002,
partially offset by decreased revenues from the sale of the ManChief facility in
2001.

     Operating expenses include the cost of fuel used in the power generation
processes, asset impairments and other costs we incur in operating and
maintaining our power plants. Operating expenses for the year ended December 31,
2002, were $133 million higher than in 2001 primarily as a result of a $79
million increase in plant operation and maintenance expenses and a $16 million
increase in depreciation expense, which both resulted from the consolidation of
international and domestic power-related entities in the first quarter of 2002.
Operating expenses also increased due to a $35 million increase in fuel costs to
run the plants as a result of higher fuel prices during 2002. We also wrote down
our capitalized turbine costs by $18 million in 2002 as El Paso reduced its
capital expenditure plans related to future power developments as a result of El
Paso's liquidity concerns, and accordingly our ability and intent to use the
turbines in international and domestic power development projects changed.

     Other income for the year ended December 31, 2002, was $213 million lower
than in 2001 primarily due to a decrease in equity earnings from projects
consolidated in the fourth quarter of 2001 and first quarter of 2002 of $52
million. Also contributing to the decrease was $51 million of minority owner's
interest in income of projects consolidated by us in 2002 and a $22 million
decrease in operating lease income as a result of the consolidation of Nejapa in
2002.

                                        25
<PAGE>

  PETROLEUM

     We announced in February 2003 our intent to exit substantially all of our
petroleum businesses, except for our Aruba refinery. We currently own or have
interests in oil refineries, chemical production facilities, petroleum
terminalling and marketing operations, and blending and packaging operations for
lubricants and automotive products. Our refinery operations are cyclical in
nature and sensitive to movements in the price of crude oil. During the last two
years, we have operated in an environment where the differences in the price of
our crude oil input and the price we can realize for the resulting products
output has been so narrow that we have experienced losses in our refinery
operations. While the condition has improved during the first quarter of 2003,
our results in the future may continue to be volatile. Also contributing to
losses in 2002 and 2001 were operational difficulties following a fire at our
Aruba facility in 2001.

PETROLEUM DIVISION RESULTS

<Table>
<Caption>
                                                              2002     2001
                                                              -----   -------
                                                               (IN MILLIONS)
<S>                                                           <C>     <C>
Gross margin................................................  $ 546   $   806
Operating expenses..........................................   (872)   (1,028)
                                                              -----   -------
  Operating loss............................................   (326)     (222)
Other income................................................    110       112
                                                              -----   -------
  EBIT......................................................  $(216)  $  (110)
                                                              =====   =======
</Table>

     Gross margin consists of revenues from our refineries and commodity trading
activities, less costs of the feedstocks used in the refining process and the
costs of commodities sold. For the year ended December 31, 2002, our gross
margin was $260 million lower than in 2001. This decrease was primarily due to
lower refining margins of $84 million resulting from lower throughput at our
Aruba refinery. Also, we recorded $57 million of insurance claims and recoveries
in 2001 related to our refinery losses associated primarily with a fire at our
Aruba facility in April 2001, a decrease of $143 million in marine revenues
resulting from lower marine freight rates and number of operating vessels and a
decrease of $86 million associated with the lease of our Corpus Christi refinery
and related assets to Valero in June 2001. These decreases were partially offset
by increased refining margins of $74 million at our Eagle Point refinery.

     Operating expenses for the year ended in December 31, 2002, were $156
million lower than in 2001. The decrease was primarily due to $244 million of
merger-related costs, asset impairments and other charges in 2001 primarily
associated with combining our operations with El Paso's operations. This
decrease was partially offset by a $91 million impairment of our MTBE chemical
processing plant in 2002. See Item 8, Financial Statements and Supplementary
Data, Note 3 and 4, for a discussion of our merger-related costs and asset
impairments of our long-lived assets.

     Other income for the year ended December 31, 2002, was $2 million lower
than in 2001. This decrease was primarily due to lower equity earnings of $17
million in 2002 from our Estonia and Subic Bay equity investments. These
decreases were partially offset by $46 million of insurance claims and
recoveries from our insurers recorded in 2002 compared to $40 million net of
writeoffs of damaged properties in 2001, primarily associated with the assets
destroyed in a fire at our Aruba facility in April 2001.

CORPORATE AND OTHER EXPENSES, NET

     Our Corporate and Other operations include our general and administrative
activities, as well as other miscellaneous businesses. For the year ended
December 31, 2002, Corporate and Other Expenses were $680 million lower than in
2001. The decrease was primarily due to a charge of $520 million in
merger-related costs for 2001, in connection with our merger with El Paso.
Additional costs for the year ended December 31, 2001 were charges of $144
million related to increased estimates of environmental remediation and
reductions in fair value of spare parts inventories to reflect changes in
usability of spare parts inventories in

                                        26
<PAGE>

our corporate operations based on an ongoing evaluation of our operating
standards and plans following the merger.

INTEREST AND DEBT EXPENSE

     Interest and debt expense for the year ended December 31, 2002, was $14
million lower than in 2001. Below is an analysis of our interest expense during
the year ended December 31 (in millions):

<Table>
<Caption>
                                                               2002     2001
                                                              ------   ------
<S>                                                           <C>      <C>
Long term debt, including current maturities................  $  414   $  390
Commercial paper............................................      --        7
Other interest..............................................      37       86
Less: Capitalized interest..................................     (18)     (36)
                                                              ------   ------
       Total interest expense...............................  $  433   $  447
                                                              ======   ======
</Table>

     Interest expense on long-term debt for the year ended December 31, 2002,
was $24 million higher than in 2001 primarily due to $37 million increase in
interest from UCF and Mohawk River Funding IV as a result of our consolidation
of these companies in 2002. Proceeds from these borrowings were used for ongoing
capital projects, investment programs and operating requirements. 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 no amounts
outstanding related to short-term credit facilities during 2002.

     Other interest for the year ended December 31, 2002, was $49 million lower
than in 2001. The decrease was primarily due to a $22 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.

     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

     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 interest rates for the
year decreased from 4.3% in 2001 to 1.8% in 2002. The average advance payables
balance decreased from $1 billion in 2001 to $470 million in 2002.

MINORITY INTEREST IN CONSOLIDATED SUBSIDIARIES

     Expense associated with minority interest in consolidated subsidiaries for
the year ended December 31, 2002, was $52 million higher than in 2001. This
increase was primarily due to 2002 income of $38 million related to the minority
interest owners share of income on Eagle Point Cogeneration, Utility Contract
Funding, CDECCA and Mohawk River Funding IV. We consolidated these companies
during 2002. An additional $13 million of the increase related to the minority
owner's share of the gain from the termination of the Nejapa power purchase
agreement.

                                        27
<PAGE>

RETURNS ON PREFERRED INTERESTS OF CONSOLIDATED SUBSIDIARIES

     Returns 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 14.

INCOME TAX EXPENSE

     Income tax benefit for the year ended December 31, 2002, was $35 million
resulting in an effective tax rate of 17 percent. For the year ended December
31, 2001, income tax expense was $81 million, resulting in an effective tax rate
of (89) percent. Of the 2001 amount, $106 million related to non-deductible
merger charges and changes in our estimate of additional tax liabilities. The
majority of these estimated additional liabilities were paid in 2001 and are
being contested by us. The effective tax rate excluding these charges was 28
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;

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

     - foreign income taxed at different rates;

     - non-deductible dividends on the preferred stock of a subsidiary;

     - depreciation, depletion and amortization; and

     - goodwill impairment.

     For a reconciliation of the statutory rate of 35 percent to the effective
rates, see Item 8, Financial Statements and Supplementary Data, Note 8.

                        LIQUIDITY AND CAPITAL RESOURCES

  LIQUIDITY

     We rely on cash generated from our internal operations and loans from our
parent company through El Paso's cash management program as our primary sources
of liquidity, as well as available credit facilities, bank financings, asset
sales and the issuance of long-term debt, preferred securities and equity
securities. We expect that our future funding for working capital needs, capital
expenditures, long-term debt repayments, dividends and other financing
activities will continue to be provided from some or all of these sources. Each
of these sources are 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. Collateral
demands or recovery of collateral posted are impacted by natural gas prices,
hedging levels and our credit quality and that of our counterparties. Liquidity
generated by future asset sales may depend on the overall economic conditions of
the industry served by these assets, the condition and location of the assets
and the number of interested buyers. In addition, our credit ratings or general
market conditions can restrict our ability to access capital markets, which can
have a significant impact on our liquidity. See a further discussion of these
and other risks that could impact us beginning on page 34.

                                        28
<PAGE>

     In a series of credit rating agency actions in late 2002 and early 2003,
and contemporaneously with the downgrades of the senior unsecured indebtedness
of El Paso, our senior unsecured indebtedness was downgraded to below investment
grade and is currently rated Caa1 by Moody's and B by Standard & Poor's. We
remain on negative outlook by both agencies. These downgrades will increase our
cost of capital and could impede our access to capital markets in the future.
These downgrades also resulted in cash generated by several of our consolidated
companies that collateralize a minority interest financing arrangement being
largely unavailable to us for general corporate purposes. Instead, we are
required to use this cash to redeem preferred securities issued in connection
with this arrangement and for the operation of those companies. In February
2003, we paid approximately $103 million under this provision. This provision
will continue until the amounts outstanding under the financing arrangement have
been repaid. As of December 31, 2002, the total amount outstanding on this
arrangement was approximately $950 million.

     Under El Paso's cash management 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. As of December 31, 2002 we had borrowed $2.4
billion from El Paso.

     In August 2002, the FERC issued a notice of proposed rulemaking requiring,
among other things, that FERC regulated entities participating in cash
management arrangements with non-FERC regulated parents maintain a minimum
proprietary capital balance of 30 percent, and that the FERC regulated entity
and its parent maintain investment grade credit ratings as a condition to
participating in the cash management program. If this proposal were adopted, the
cash management program between El Paso and our FERC-regulated subsidiaries
could terminate, which could affect our liquidity. We cannot predict the outcome
of this rulemaking at this time.

     Our cash flows from continuing operations for the years ended December 31
were as follows:

<Table>
<Caption>
                                                                YEAR ENDED
                                                              --------------
                                                              2002    2001
                                                              ----   -------
                                                              (IN MILLIONS)
<S>                                                           <C>    <C>
Cash flows from operating activities........................  $165   $ 1,945
Cash flows from investing activities........................   (85)   (1,958)
Cash flows from financing activities........................   (93)       97
</Table>

     As a result of our downgrades, our access to cash from the capital markets
has been limited. In order to improve our liquidity position, we have taken
steps to reduce our cash needs for 2003, including implementing cost savings
plans, exiting marginally performing businesses with high working capital
requirements, and reducing our overall capital spending program. In order to
supplement our cash generated from operations in 2002, we sold $1.8 billion of
assets. We expect to continue to sell assets in 2003 to supplement our
liquidity. In March 2003, we generated $400 million of cash from the issuance of
debt at our ANR Pipeline subsidiary.

     In addition to our sources of cash from internally generated funds, asset
sales and capital markets transactions, we also will rely on advances from El
Paso through the use of El Paso's cash management program. Our ability to
continue to rely on cash advances from our parent can be impacted by our parent
company's own credit standing, their requirements to repay debt and other
financing obligations, and the cash demands from other parts of its business.

     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 as discussed below.

                                        29
<PAGE>

  CAPITAL EXPENDITURES AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES

     Our capital expenditures and investments in unconsolidated affiliates by
segments during the periods indicated are listed below:

<Table>
<Caption>
                                                                YEAR ENDED
                                                               DECEMBER 31,
                                                              ---------------
                                                               2002     2001
                                                              ------   ------
                                                               (IN MILLIONS)
<S>                                                           <C>      <C>
Pipelines...................................................  $  252   $  421
Production..................................................   1,124    1,814
Field Services..............................................      20       53
Merchant Energy.............................................     281      142
Other.......................................................      98      136
                                                              ------   ------
     Total..................................................  $1,775   $2,566
                                                              ======   ======
</Table>

     Under our current plan, we expect to spend between approximately $938
million and $1,018 million in each of the next three years 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.

  DEBT

     The following table shows our total long-term debt as of December 31, 2002:

<Table>
<Caption>
                                                                  2002
                                                              -------------
                                                              (IN MILLIONS)
<S>                                                           <C>
Long-term debt
  El Paso CGP...............................................     $3,242
  El Paso Power.............................................      1,041
  El Paso Production Company................................        200
  ANR Pipeline..............................................        513
  Colorado Interstate Gas...................................        280
  Other.....................................................         84
                                                                 ------
                                                                  5,360
  Less:
     Unamortized discount...................................          6
     Current maturities.....................................        369
                                                                 ------
          Total long-term debt, less current maturities.....     $4,985
                                                                 ======
</Table>

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

<Table>
  <S>                                                           <C>
  2003........................................................  $  369
  2004........................................................     556
  2005........................................................     364
  2006........................................................     655
  2007........................................................      60
  Thereafter..................................................   3,356
                                                                ------
       Total long-term debt and other financing obligations
        including current maturities..........................  $5,360
                                                                ======
</Table>

                                        30
<PAGE>

  Credit Facilities

     In June 2002, El Paso amended its existing $1 billion 3-year revolving
credit and competitive advance facility to permit El Paso to issue up to $500
million in letters of credit and to adjust pricing terms. This facility matures
in August 2003. We are a designated borrower under this facility and, as such,
are jointly and severally liable for any amounts outstanding under this
facility. The interest rate varies based on El Paso's senior unsecured debt
rating, and as of December 31, 2002, an initial draw would have had a rate of
LIBOR plus 1.00% plus a 0.25% utilization fee. As of December 31, 2002, there
were no borrowings outstanding, and $456 million in letters of credit were
issued under the $1 billion facility. In February 2003, El Paso borrowed $500
million under the $1 billion facility.

     The availability of borrowings under our credit and borrowing agreements is
subject to specified conditions, which we currently meet. These conditions
include compliance with the financial covenants and ratios required by such
agreements, absence of default under such agreements, and continued accuracy of
the representations and warranties contained in such agreements. As a result of
downgrades in our credit ratings, the current interest rate on an initial draw
under both of the facilities would be at a rate of LIBOR plus 1.00%, plus a
0.25% utilization fee for drawn amounts above 25% of the committed amounts.

  Restrictive Covenants

     We have entered into debt instruments and guaranty agreements that contain
covenants such as restrictions on debt levels, restrictions on liens securing
debt and guarantees, restrictions on mergers and on sales of assets,
capitalization requirements, dividend restrictions and cross-acceleration
provisions. A breach of any of these covenants could 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 $1.2 billion. If breached, the amounts guaranteed by the
guaranty agreements could be accelerated. The guaranty agreements also have a
$30 million of cross-acceleration provision.

     In addition, we have indentures associated with our public debt that
contain $5 million cross-acceleration provisions.

     During 2000, El Paso formed a series of companies that it refers to as
Clydesdale. Clydesdale was formed to provide financing to invest in various
capital projects and other assets. A third-party investor contributed cash of $1
billion into Clydesdale in exchange for the preferred securities of one of El
Paso's consolidated subsidiaries. The financing arrangement is collateralized by
a combination of notes payable from us, a production payment from us, various
natural gas and oil properties and Colorado Interstate Gas Company. The credit
downgrades of El Paso have resulted in the net cash generated by these assets
being largely unavailable to us for general corporate purposes. The cash
generated by these assets can only be used to redeem the preferred securities
issued in connection with these arrangements, and for the operations of the
business units associated with this transaction. As of December 31, 2002, the
total amount outstanding on the Clydesdale transaction was $950 million.

     In a series of rating agency actions in late 2002 and early 2003, and
contemporaneously with the downgrades of the senior unsecured indebtedness of El
Paso, our senior unsecured indebtedness was downgraded below investment grade
and is currently rated Caa1 by Moody's and B by Standard & Poor's. These
downgrades will increase our cost of capital and collateral requirements and
could impede our access to capital markets in the future.

  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
                                        31
<PAGE>

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, 2002, we had approximately $50 million of guarantees in
connection with our international development and operating activities not
consolidated on our balance sheet and approximately $11 million of guarantees in
connection with our domestic development and operating activities not
consolidated on our balance sheet.

  Residual Value Guarantees

     Under one of our operating leases, we have provided a residual value
guarantee to the lessor. Under this guarantee, we can either choose to purchase
the asset at the end of the lease term for a specified amount, which is equal to
the outstanding loan amount owed by the lessor, or we can choose to assist in
the sale of the leased asset to a third party. Should the asset not be sold for
a price that equals or exceeds the amount of the guarantee, we would be
obligated for the shortfall. The level of our residual value guarantee is 89.9
percent of the original cost of the leased assets. Accounting for this residual
value guarantee will be impacted effective July 1, 2003 by our adoption of the
new accounting rules on consolidations. For a discussion of the accounting
impact of these new rules, see Note 1.

     As of December 31, 2002, we had a purchase option and residual value
guarantee associated with the operating lease for the following asset:

<Table>
<Caption>
                                                      PURCHASE   RESIDUAL VALUE     LEASE
ASSET DESCRIPTION                                      OPTION      GUARANTEE      EXPIRATION
-----------------                                     --------   --------------   ----------
                                                                  (IN MILLIONS)
<S>                                                   <C>        <C>              <C>
Facility at Aruba refinery..........................    $370          $333           2006
</Table>

                                 RECENT EVENTS

     In January 2003, we retired various debt obligations of approximately $47
million. In February 2003, Valero exercised its option to purchase our Corpus
Christi refinery and we used the proceeds to repay a $240 million loan that was
secured by the refinery lease with Valero.

     In February 2003, ANR also distributed to its parent $400 million of
intercompany receivables.

     In March, 2003, ANR issued $300 million of 8 7/8% senior unsecured notes
due 2010, raising net proceeds of $288 million. ANR used $263 million of cash
proceeds from the offering to reduce existing intercompany payables. ANR
retained $25 million of net proceeds from the offering to fund future capital
expenditures.

                         COMMITMENTS AND CONTINGENCIES

     For a discussion of our commitments and contingencies, see Item 8,
Financial Statements and Supplementary Data, Note 16 and is incorporated herein
by reference.

            NEW ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

     As of December 31, 2002, there were a number of accounting standards and
interpretations that had been issued, but not yet adopted by us. Below is a
discussion of the more significant standards that could impact us.

  Accounting for Asset Retirement Obligations

     In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS
No. 143, Accounting for Asset Retirement Obligations. This statement requires
companies to record a liability for the estimated retirement and removal costs
of long-lived assets used in their business. The liability is recorded at its
fair value, with a corresponding asset which is depreciated over the remaining
useful life of the long-lived asset to which the liability relates. An ongoing
expense will also be recognized for changes in the value of the liability as a
result of the passage of time. The provisions of SFAS No. 143 are effective for
fiscal years beginning after

                                        32
<PAGE>

June 15, 2002. We expect that we will record a charge as a cumulative effect of
accounting change of approximately $21 million, net of income taxes, upon our
adoption of SFAS No. 143 on January 1, 2003. We also expect to record
non-current retirement assets of $106 million and non-current retirement
liabilities of $135 million on January 1, 2003. Our liability relates primarily
to our obligations to plug abandoned wells in our Production and Pipelines
segments over the next four to 24 years.

  Accounting for Costs Associated with Exit or Disposal Activities

     In July 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated
with Exit or Disposal Activities. This statement will require us to recognize
costs associated with exit or disposal activities when they are incurred rather
than when we commit to an exit or disposal plan. Examples of costs covered by
this guidance include lease termination costs, employee severance costs
associated with a restructuring, discontinued operations, plant closings or
other exit or disposal activities. The statement is effective for fiscal years
beginning after December 31, 2002, and will impact any exit or disposal
activities we initiate after January 1, 2003.

  Accounting for Guarantees

     In November 2002, the FASB issued FIN No. 45, Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others. This interpretation requires that companies record a
liability for all guarantees issued after January 31, 2003, including financial,
performance and fair value guarantees. This liability is recorded at its fair
value upon issuance and does not affect any existing guarantees issued before
January 31, 2003. This standard also requires expanded disclosures on all
existing guarantees at December 31, 2002. We have included these required
disclosures in Item 8, Financial Statements and Supplementary Data, Note 16.

  Consolidation of Variable Interest Entities

     In January 2003, the FASB issued 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 that companies 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. The provisions of FIN No. 46 are effective for all variable
interest entities created after January 31, 2003, and are effective on July 1,
2003, for all variable interest entities created before January 31, 2003. We are
currently evaluating the effects of this pronouncement, but have reached several
tentative conclusions about the possible impact of this interpretation on us.
See Item 8, Financial Statements and Supplementary Data, Note 1, for a
discussion of the conclusion reached.

    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. Our forward-looking statements,
whether written or oral, are expressly qualified by these cautionary statements
and any other cautionary statements that

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may accompany those 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 Commission from time to time
and the following important factors that could cause actual results to differ
materially from those expressed in any forward-looking statement made by us or
on our behalf.

                         RISKS RELATED TO OUR BUSINESS

THE SUCCESS OF OUR PIPELINE AND FIELD SERVICES BUSINESSES DEPENDS ON FACTORS
BEYOND OUR CONTROL.

     Most of the natural gas and natural gas liquids we transport, gather,
process and store are owned by third parties. As a result, the volume of natural
gas involved in these activities depends on the actions of those third parties,
and is beyond our control. Further, the following factors, most of which are
beyond our control, may unfavorably impact our ability to maintain or increase
current throughput, to renegotiate existing contracts as they expire, or to
remarket unsubscribed capacity:

     - future weather conditions, including those that favor alternative energy
       sources;

     - price competition;

     - drilling activity and supply availability;

     - expiration and/or turn back of significant capacity;

     - service area competition;

     - changes in regulation and actions of regulatory bodies;

     - credit risk of customer base;

     - increased cost of capital; and

     - 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 you that we will be able to extend or replace
these contracts when they expire or that the terms of any renegotiated contracts
will be as favorable as the existing contracts.

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

     - 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.

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<PAGE>

FLUCTUATIONS IN ENERGY COMMODITY PRICES COULD ADVERSELY AFFECT OUR BUSINESS.

     Revenues generated by our transmission, storage, gathering 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
loss of load from our customers, such as power companies not dispatching gas
fired power plants, industrial plant shut down or load loss to competitive fuels
and local distribution companies' loss of customer base. The success of our
transmission, gathering 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
could precipitate a decrease in these development activities and could cause a
decrease in the volume of reserves available for transmission, gathering and
processing through our systems or facilities. 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.

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 rate 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, the profitability of our pipeline businesses
could be reduced.

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

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

     The performance of our natural gas and oil exploration and production
businesses is dependent upon a number of factors that we cannot control. These
factors include:

     - fluctuations in natural gas and crude oil prices including basis
       differentials;

     - the results of future drilling activity;

     - 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 leasing conditions;

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

     - risks incident to operations of natural gas and oil wells;

     - 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;

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<PAGE>

     - 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; and

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

ESTIMATES OF NATURAL GAS AND OIL RESERVES MAY CHANGE.

     Actual production, revenues, taxes, development expenditures, and operating
expenses with respect to our reserves will likely vary from our estimates of
proved reserves of natural gas and oil, and those variances may be material. The
process of estimating natural gas and oil reserves is complex, requiring
significant decisions and assumptions in the evaluation of available geological,
geophysical, engineering, and economic data for each reservoir or deposit. As a
result, these estimates are inherently imprecise. Actual future production,
natural gas and oil prices, revenues, taxes, development expenditures, operating
expenses and quantities of recoverable natural gas and oil reserves may vary
substantially from our estimates. In addition, we may be required to revise the
reserve information, downward or upward, based on production history, results of
future exploration and development, prevailing natural gas and oil prices and
other factors, many of which are beyond our control.

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

     The success of our 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, restructure or
       recontract advantageous long-term power purchase 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; and

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

OUR OBJECTIVES IN EXITING THE ENERGY TRADING BUSINESS AND THE PETROLEUM BUSINESS
MAY NOT BE ACHIEVED IN THE TIME PERIOD OR IN THE MANNER WE EXPECT, IF AT ALL.

     In November 2002, El Paso announced our intention to exit the energy
trading business and pursue an orderly liquidation of our trading portfolio. In
February 2003, El Paso announced our intention to sell our remaining petroleum
assets, excluding the Aruba refinery. If we are unable to achieve these
objectives in the time period or the manner that we expect, it could have a
substantial negative impact on our cash flows, liquidity and financial position.
The ability to achieve our goals in the liquidation of our trading portfolio is
subject to factors beyond our control, including, among others, liquidity
constraints experienced by the counterparties in our energy trading business,
obtaining maximum cash flow from our trading portfolio and

                                        36
<PAGE>

isolating the credit and liquidity needs of the energy trading business from the
rest of our business. Additionally, any amounts actually realized from the
liquidation of the energy trading business could be significantly less than the
amounts we currently expect from such liquidations. Ongoing losses from our
trading business are expected to be incurred as positions are liquidated. The
ability to achieve our goals in the sale of our petroleum assets is subject to
factors beyond our control, including, among others, our ability to locate
potential buyers in a timely fashion and obtain a reasonable price, and
competing asset sales programs by our competitors.

OUR USE OF DERIVATIVE FINANCIAL INSTRUMENTS COULD RESULT IN FINANCIAL LOSSES.

     Some of our subsidiaries use futures, swaps and option contracts traded on
the New York Mercantile Exchange, over-the-counter options and price and basis
swaps with other natural gas merchants and financial institutions. We could
incur financial losses in the future as a result of volatility in the market
values of the energy commodities we trade, or if one of our counterparties fails
to perform under a contract. The valuation of these financial instruments can
involve estimates. Changes in the assumptions underlying these estimates can
occur, changing our valuation of these instruments and potentially resulting in
financial losses. To the extent we hedge our commodity price exposure and
interest rate exposure, we forego the benefits we would otherwise experience if
commodity prices were to increase, or interest rates were to change. The use of
derivatives also requires the posting of cash collateral with our counterparties
which can impact our working capital when commodity prices or interest rates
change. For additional information concerning our derivative financial
instruments, see Item 7A, Quantitative and Qualitative Disclosures About Market
Risk and Item 8, Financial Statements and Supplementary Data, Note 11.

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.

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 Superfund
sites by the 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.

     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;

     - 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. For additional

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<PAGE>

information concerning our environmental matters, see Item 8, Financial
Statements and Supplementary Data, Note 16.

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, our financial
condition and operations could be adversely affected if a significant event
occurs that is not fully covered by insurance.

TERRORIST ATTACKS AIMED AT OUR FACILITIES COULD ADVERSELY AFFECT OUR BUSINESS.

     On September 11, 2001, the U.S. was the target of terrorist attacks of
unprecedented scale. Since the September 11th attacks, the U.S. government has
issued warnings that energy assets, including our nation's pipeline
infrastructure, may be a future target of terrorist organizations. These
developments have subjected our operations to increased risks. Any future
terrorist attack on our facilities, those of our customers and, in some cases,
those of other pipelines, could have a material adverse effect on our business.

WE WILL FACE COMPETITION FROM THIRD PARTIES TO PRODUCE, TRANSPORT, GATHER,
PROCESS, FRACTIONATE, STORE OR OTHERWISE HANDLE NATURAL GAS, OIL, NATURAL GAS
LIQUIDS AND OTHER PETROLEUM PRODUCTS.

     The natural gas and oil business is highly competitive in the search for
and acquisition of reserves and in the gathering and marketing of natural gas
and oil production. Our competitors include the major oil companies, independent
oil and gas concerns, individual producers, gas marketers and major pipeline
companies, as well as participants in other industries supplying energy and fuel
to industrial, commercial and individual consumers. If we are unable to compete
effectively with services offered by other energy enterprises, our future
profitability may be negatively impacted.

                 RISKS RELATED TO OUR AFFILIATION WITH EL PASO

     El Paso files reports, proxy statements and other information with the SEC
under the Securities Exchange Act of 1934, as amended. Each prospective investor
should consider this information and the matters disclosed therein in addition
to the matters described in this report. Such information is not incorporated by
reference herein.

OUR RELATIONSHIP WITH EL PASO AND ITS FINANCIAL CONDITION SUBJECTS US TO
POTENTIAL RISKS THAT ARE BEYOND OUR CONTROL.

     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 outstanding senior unsecured
indebtedness of El Paso has been downgraded to below investment grade, currently
rated Caa1 by Moody's and B by Standard & Poor's (with a negative outlook at
both agencies), which in turn resulted in a similar downgrading of our
outstanding senior unsecured indebtedness to Caa1 by Moody's and B by Standard &
Poor's (with a negative outlook at both agencies). These downgrades will
increase our cost of capital and collateral requirements, and could impede our
access to capital markets. As a result of these recent downgrades, El Paso has
realized substantial demands on its liquidity, which demands have included:

     - application of cash required to be withheld from El Paso's cash
       management program in order to redeem preferred membership interests at
       one of El Paso's minority interest financing structures; and

     - cash collateral or margin requirements associated with contractual
       commitments of El Paso subsidiaries.

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<PAGE>

These downgrades may subject El Paso to additional liquidity demands in the
future. These downgrades are a result, at least in part, of the outlook
generally for the consolidated businesses of El Paso and its needs for
liquidity.

     In order to meet its short term liquidity needs, El Paso has embarked on
its 2003 Operational and Financial Plan that contemplates drawing all or part of
its availability under its existing bank facilities and consummating significant
asset sales. In addition, El Paso may take additional steps, such as entering
into other financing activities, renegotiating its credit facilities and further
reducing capital expenditures, which should provide additional liquidity. There
can be no assurance that these actions will be consummated on favorable terms,
if at all, or even if consummated, that such actions will be successful in
satisfying El Paso's liquidity needs. In the event that El Paso's liquidity
needs are not satisfied, El Paso could be forced to seek protection from its
creditors in bankruptcy. Such a development could materially adversely affect
our financial condition.

     Pursuant to El Paso's cash management program, surplus cash is made
available to us in exchange for an affiliated payable. In addition, we conduct
commercial transactions with some of our affiliates. As of December 31, 2002, we
have net payables of approximately $2.4 billion to El Paso and its affiliates.
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. However, we
might still be required to satisfy affiliated company payables. For a further
discussion of these matters, see Part II, Item 8, Financial Statements and
Supplementary Data, Note 20.

WE ARE JOINTLY AND SEVERALLY LIABLE FOR ALL OUTSTANDING AMOUNTS UNDER EL PASO'S
$1 BILLION, 3-YEAR REVOLVING CREDIT AND COMPETITIVE ADVANCE FACILITY.

     We are a designated borrower under El Paso's $1 billion, 3-year revolving
credit and competitive advance facility. As such, we are jointly and severally
liable for any amounts outstanding under this facility. As of March 1, 2003,
$956 million (including $456 million in letters of credit) was outstanding under
the $1 billion facility. If, for any reason, El Paso does not repay any of the
outstanding amounts under this facility, and we are required to repay any such
amounts, our financial condition and liquidity could be materially adversely
affected.

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.

ONGOING LITIGATION AND INVESTIGATIONS REGARDING EL PASO COULD SIGNIFICANTLY
ADVERSELY AFFECT OUR BUSINESS.

     On March 20, 2003, El Paso entered into an agreement in principle (the
Western Energy Settlement) with various public and private claimants, including
the states of California, Washington, Oregon, and Nevada, to resolve the
principal litigation, claims, and regulatory proceedings against El Paso and its
subsidiaries relating to the sale or delivery of natural gas and electricity
from September 1996 to the date of the Western Energy Settlement. A more
detailed description of the Western Energy Settlement can be found

                                        39
<PAGE>

in El Paso's reports filed with the SEC. If El Paso is unable to negotiate
definitive settlement agreements, or if the settlement is not approved by the
courts or the FERC, the proceedings and litigation will continue.

     Since July 2002, twelve purported shareholder class action suits alleging
violations of federal securities laws have been filed against El Paso and
several of its officers. Eleven of these suits are now consolidated in federal
court in Houston before a single judge. The suits generally challenge the
accuracy or completeness of press releases and other public statements made
during 2001 and 2002. The twelfth shareholder class action lawsuit was filed in
federal court in New York City in October 2002 challenging the accuracy or
completeness of El Paso's February 27, 2002 prospectus for an equity offering
that was completed on June 21, 2002. It has since been dismissed, in light of
similar claims being asserted in the consolidated suits in Houston. Four
shareholder derivative actions have also been filed. One shareholder derivative
lawsuit was filed in federal court in Houston in August 2002. This derivative
action generally alleges the same claims as those made in the shareholder class
action, has been consolidated with the shareholder class actions pending in
Houston and has been stayed. A second shareholder derivative lawsuit was filed
in Delaware State Court in October 2002 and generally alleges the same claims as
those made in the consolidated shareholder class action lawsuit. A third
shareholder derivative suit was filed in state court in Houston in March 2002,
and a fourth shareholder derivative suit was filed in state court in Houston in
November 2002. These two shareholder derivative suits have not been consolidated
with the shareholder action pending in federal court in Houston. The third and
fourth shareholder derivative suits both generally allege that manipulation of
California gas supply and gas prices exposed El Paso to claims of antitrust
conspiracy, FERC penalties and erosion of share value. Another action was filed
against El Paso in December 2002, on behalf of participants in El Paso's 401(k)
plan. At this time, El Paso's legal exposure related to these lawsuits and
claims is not determinable.

     If El Paso does not prevail in these cases (or any of the other litigation,
administrative or regulatory matters disclosed in El Paso's 2002 Form 10-K to
which El Paso is, or may be, a party), and if the remedy adopted in these cases
substantially impairs El Paso's financial position, the long-term adverse impact
on El Paso's credit rating, liquidity and its ability to raise capital to meet
its ongoing and future investing and financing needs could be substantial. Such
a negative impact on El Paso could have a material adverse effect on us as well.

THE PROXY CONTEST INITIATED BY SELIM ZILKHA TO REPLACE EL PASO'S BOARD OF
DIRECTORS COULD HAVE A MATERIAL ADVERSE EFFECT ON US.

     On February 18, 2003, Selim Zilkha, a stockholder of El Paso, announced his
intention to initiate a proxy solicitation to replace El Paso's entire board of
directors with his own nominees and on March 11, 2003, Mr. Zilkha filed his
preliminary proxy statement to that effect with the SEC. This proxy contest may
be highly disruptive and may negatively impact El Paso's ability to achieve the
stated objectives of its 2003 Operational and Financial Plan. In addition, El
Paso may have difficulty attracting and retaining key personnel until such proxy
contest is resolved. Therefore, this proxy contest, whether or not successful,
could have a material adverse effect on El Paso's liquidity and financial
condition, which, in turn, could adversely affect our liquidity and financial
position.

RESULTS OF INVESTIGATIONS INTO REPORTING OF TRADING INFORMATION COULD ADVERSELY
AFFECT OUR BUSINESS.

     In response to an October 2002 data request from the FERC, El Paso
conducted an investigation into the accuracy of information that employees of El
Paso Merchant Energy, an El Paso subsidiary, voluntarily reported to trade
publications. As a part of that investigation, El Paso discovered that
inaccurate information was submitted to the trade publications. One of El Paso
Merchant Energy's former employees has been arrested and charged with knowingly
submitting inaccurate data to a trade publication. El Paso has continued its
policy of cooperation with the office of the U.S. Attorney and the FERC and
intends to take whatever remedial steps are necessary to ensure that its
operations are conducted with integrity. However, these investigations are
continuing, and there can be no assurance that penalties or sanctions will not
be imposed on El Paso, which, in turn, could adversely affect our business.

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<PAGE>

WE ARE A WHOLLY OWNED SUBSIDIARY OF EL PASO.

     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.

                      RISKS RELATED TO OUR LONG-TERM DEBT

OUR SUBSTANTIAL LONG-TERM DEBT COULD IMPAIR OUR FINANCIAL CONDITION AND OUR
ABILITY TO FULFILL OUR DEBT OBLIGATIONS.

     We have substantial long-term debt. As of December 31, 2002, we had total
long-term debt of approximately $5.4 billion.

     Our substantial long-term debt could have important consequences. For
example, it could:

     - make it more difficult for us to satisfy our obligations with respect to
       our long-term debt, which could in turn result in an event of default on
       any or all of such long-term debt;

     - impair our ability to obtain additional financing in the future for
       working capital, capital expenditures, acquisitions, general corporate
       purposes or other purposes;

     - diminish our ability to withstand a downturn in our business or the
       economy generally;

     - require us to dedicate a substantial portion of our cash flow from
       operations to debt service payments, thereby reducing the availability of
       cash for working capital, capital expenditures, acquisitions, general
       corporate purposes or other purposes;

     - limit our flexibility in planning for, or reacting to, changes in our
       business and the industry in which we operate; and

     - place us at a competitive disadvantage compared to our competitors that
       have proportionately less debt.

     If we are unable to meet our debt service obligations, we could be forced
to restructure or refinance our long-term debt, seek additional equity capital
or sell assets. We may be unable to obtain financing or sell assets on
satisfactory terms, or at all.

     Covenants applicable to our long-term debt allow us to incur significant
amounts of additional indebtedness. Our incurrence of significant additional
indebtedness would exacerbate the negative consequences mentioned above, and
could adversely affect our ability to repay our long-term debt.

A BREACH OF THE COVENANTS APPLICABLE TO OUR LONG-TERM DEBT AND OTHER FINANCIAL
OBLIGATIONS COULD ACCELERATE OUR LONG-TERM DEBT AND OTHER FINANCIAL OBLIGATIONS
AND THAT OF OUR SUBSIDIARIES.

     Our long-term debt and other financial obligations contain restrictive
covenants and cross-acceleration provisions. A breach of any of these covenants
could accelerate our long-term debt and other financial obligations and that of
our subsidiaries. If this were to occur, we may not be able to repay such
long-term debt and other financing obligations upon such acceleration.

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OUR LONG-TERM DEBT IS EFFECTIVELY SUBORDINATED TO LIABILITIES AND INDEBTEDNESS
OF OUR SUBSIDIARIES AND SUBORDINATED TO ANY OF OUR SECURED INDEBTEDNESS TO THE
EXTENT OF THE ASSETS SECURING SUCH INDEBTEDNESS.

     Holders of any secured indebtedness that have claims with respect to our
assets constituting collateral for such indebtedness that are prior to the
claims of the holders of our long-term debt. In the event of a default on such
secured indebtedness or our bankruptcy, liquidation or reorganization, those
assets would be available to satisfy obligations with respect to the
indebtedness secured thereby before any payment could be made on our long-term
debt. Accordingly, any such secured indebtedness would effectively be senior to
our long-term debt to the extent of the value of the collateral securing the
indebtedness. While the indentures governing our long-term debt place
limitations on our ability to create liens, there are significant exceptions to
these limitations, including with respect to sale and leaseback transactions,
that will allow us to secure some kinds of indebtedness without equally and
ratably securing our long-term debt. To the extent the value of the collateral
is not sufficient to satisfy the secured indebtedness, the holders of that
indebtedness would be entitled to share with the holders of our long-term debt
and the holders of other claims against us with respect to our other assets.

     In addition, our long-term debt is not guaranteed by our subsidiaries and
our subsidiaries are not prohibited under our indentures from incurring
additional indebtedness. As a result, holders of our long-term debt will be
effectively subordinated to claims of third party creditors, including holders
of indebtedness, of these subsidiaries. Claims of those other creditors,
including trade creditors, secured creditors, governmental authorities, and
holders of indebtedness or guarantees issued by the subsidiaries, will generally
have priority as to the assets of the subsidiaries over claims by the holders of
our long-term debt. As a result, rights of payment of holders of our
indebtedness, including the holders of our long-term debt, will be effectively
subordinated to all those claims of creditors of our subsidiaries.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     We use derivative financial instruments and energy related contracts to
manage market risks associated with energy commodities and interest rates. Our
primary market risk exposures are those related to changing commodity prices.
Our market risks are monitored by a corporate risk management committee to
ensure compliance with El Paso's stated risk management policies approved by the
Audit Committee of El Paso's Board of Directors. This committee operates
independently from the business segments that create or manage these risks.

COMMODITY PRICE RISK

     Our segments are exposed to a variety of market risks in the normal course
of their business activities. Our Production segment has market risks related to
natural gas and oil it produces. Our Field Services segment has market risks
related to the natural gas and natural gas liquids it retains in its processing
operations. The refining activities in our Merchant Energy segment are exposed
to market risks in both the feedstocks they use, primarily crude oil and
petroleum based products as well as the refined products they sell. Our power
contract restructuring activities in Merchant Energy segment are exposed to
market risks in both the fuel the power plants use as well as the power sold
under the restructured contracts. We attempt to mitigate market risk associated
with these significant physical transactions through the use of non-trading
financial instruments, including:

     - exchange-traded futures contracts involving cash settlements;

     - forward contracts involving cash settlements or physical delivery of an
       energy commodity;

     - swap contracts which require payment to (or receipts from) counterparties
       based on the difference between a fixed and a variable price, or two
       variable prices, for a commodity; and

     - exchange-traded and over-the-counter options.

     We measure the risk associated with our commodity contracts held for
non-trading purposes on a daily basis using a Value-at-Risk model. This model
allows us to determine the maximum expected one-day unfavorable impact on the
fair value of those contracts due to normal market movement, and monitors our
risk in comparison to established thresholds. This technique uses historical
price movements and specific, defined mathematical parameters to estimate the
characteristics of and the relationships between components of our assets and
liabilities held for price risk management activities. Based on a confidence
level of 95 percent and a one-day holding period, our estimated potential
one-day unfavorable impact on earnings before interest and income taxes was $7
million and $8 million at December 31, 2002 and 2001. The highest and lowest
month-end values of our Value-at-Risk were $11 million and $2 million for 2002,
and the average of all of our month-end values of our Value-at-Risk was $7
million for 2002.

                                        43
<PAGE>

INTEREST RATE RISK

     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 weighted average interest rates
of our interest-bearing securities, by expected maturity dates and the fair
values of those securities. As of December 31, 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, 2002                               DECEMBER 31,
                                        ---------------------------------------------------------------------         2001
                                                EXPECTED FISCAL YEAR OF MATURITY OF CARRYING AMOUNTS            -----------------
                                        ---------------------------------------------------------------------   CARRYING    FAIR
                                         2003    2004   2005   2006   2007   THEREAFTER   TOTAL    FAIR VALUE   AMOUNTS    VALUE
                                        ------   ----   ----   ----   ----   ----------   ------   ----------   --------   ------
                                                                (DOLLARS IN MILLIONS)
<S>                                     <C>      <C>    <C>    <C>    <C>    <C>          <C>      <C>          <C>        <C>
LIABILITIES:
Long-term debt, including current
  portion -- fixed rate...............  $  158   $301   $252   $543   $ 52     $3,342     $4,648     $3,931      $4,365    $4,425
      Average interest rate...........     9.1%   7.2%   9.5%   7.2%   7.9%       7.8%
Long-term debt, including current
  portion -- variable rate............  $  212   $252   $111   $111   $  7     $   13     $  706     $  706      $2,052    $2,052
      Average interest rate...........     2.5%   4.4%   2.9%   2.7%   2.7%       7.2%
PREFERRED INTERESTS OF CONSOLIDATED
  SUBSIDIARIES:
Coastal Finance I.....................                                         $  300     $  300     $  160      $  300    $  299
      Average fixed interest rate.....                                            8.4%
</Table>

     The fair value of our long-term securities was significantly impacted by a
series of ratings actions initiated by Moody's and Standards & Poor's that
lowered our unsecured debt rating to Caa1 and B (both "below investment grade"
ratings), and we remain on negative outlook. These rating actions decreased the
fair value of all of our fixed rate long-term securities during 2002.

                                        44
<PAGE>

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                              EL PASO CGP COMPANY

                       CONSOLIDATED STATEMENTS OF INCOME
                                 (IN MILLIONS)

<Table>
<Caption>
                                                               YEAR ENDED DECEMBER 31,
                                                              -------------------------
                                                               2002     2001     2000
                                                              ------   ------   -------
<S>                                                           <C>      <C>      <C>
Operating revenues
  Pipelines.................................................  $  896   $  984   $   972
  Production................................................   1,163    1,818       811
  Field Services............................................     407      826       711
  Merchant Energy...........................................   6,064    4,741    11,931
  Other.....................................................      --      355     1,191
                                                              ------   ------   -------
                                                               8,530    8,724    15,616
                                                              ------   ------   -------
Operating expenses
  Cost of products and services.............................   5,221    5,074    12,309
  Operation and maintenance.................................   1,351    1,631     1,462
  Restructuring and merger-related costs....................       5      814        13
  (Gain) loss on long-lived assets..........................     791      175        (5)
  Ceiling test charges......................................     245      115        --
  Depreciation, depletion and amortization..................     681      698       642
  Taxes, other than income taxes............................     100      159       122
                                                              ------   ------   -------
                                                               8,394    8,666    14,543
                                                              ------   ------   -------
Operating income............................................     136       58     1,073
Earnings from unconsolidated affiliates.....................     104      233       281
Minority interest in consolidated subsidiaries..............     (52)      --        --
Other income................................................     118      190       126
Other expenses..............................................     (37)     (28)      (10)
Interest and debt expense...................................    (433)    (447)     (502)
Affiliated interest expense, net............................      (9)     (46)       --
Returns on preferred interests of consolidated
  subsidiaries..............................................     (35)     (51)      (60)
                                                              ------   ------   -------
Income (loss) before income taxes...........................    (208)     (91)      908
Income taxes................................................     (35)      81       253
                                                              ------   ------   -------
Income (loss) from continuing operations before
  extraordinary items and cumulative effect of accounting
  changes...................................................    (173)    (172)      655
Discontinued operations, net of income taxes................    (124)      (5)       (1)
Extraordinary items, net of income taxes....................      --      (11)       --
Cumulative effect of accounting changes, net of income
  taxes.....................................................      14       --        --
                                                              ------   ------   -------
Net income (loss)...........................................  $ (283)  $ (188)  $   654
                                                              ======   ======   =======
</Table>

                            See accompanying notes.

                                        45
<PAGE>

                              EL PASO CGP COMPANY

                          CONSOLIDATED BALANCE SHEETS
                                 (IN MILLIONS)

<Table>
<Caption>
                                                                DECEMBER 31,
                                                              -----------------
                                                               2002      2001
                                                              -------   -------
<S>                                                           <C>       <C>
                                    ASSETS
Current assets
  Cash and cash equivalents.................................  $   128   $   141
  Accounts and notes receivable
     Customer, net of allowance of $37 in 2002 and $36 in
      2001..................................................    1,537     1,793
     Affiliates.............................................      545       569
     Other..................................................      200       181
  Inventory.................................................      697       683
  Assets from price risk management activities..............      122       425
  Other.....................................................      432       279
                                                              -------   -------
          Total current assets..............................    3,661     4,071
                                                              -------   -------
Property, plant and equipment, at cost
  Natural gas and oil properties, at full cost..............    7,479     7,765
  Pipelines.................................................    6,522     6,556
  Refining, crude oil and chemical facilities...............    2,560     2,524
  Power facilities..........................................      460       272
  Gathering and processing systems..........................      279       428
  Other.....................................................       89        96
                                                              -------   -------
                                                               17,389    17,641
  Less accumulated depreciation, depletion and
     amortization...........................................    7,259     5,812
                                                              -------   -------
          Total property, plant and equipment, net..........   10,130    11,829
                                                              -------   -------
Other assets
  Investments in unconsolidated affiliates..................    1,544     1,882
  Assets from price risk management activities..............      956       267
  Intangible assets, net....................................      498       518
  Other.....................................................      444       499
                                                              -------   -------
                                                                3,442     3,166
                                                              -------   -------
          Total assets......................................  $17,233   $19,066
                                                              =======   =======
</Table>

                            See accompanying notes.

                                        46
<PAGE>
                              EL PASO CGP COMPANY

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

<Table>
<Caption>
                                                                DECEMBER 31,
                                                              -----------------
                                                               2002      2001
                                                              -------   -------
<S>                                                           <C>       <C>
                     LIABILITIES AND STOCKHOLDER'S EQUITY

Current liabilities
  Accounts payable
     Trade..................................................  $ 1,326   $ 1,832
     Affiliates.............................................       87     1,336
     Other..................................................      296       359
  Short-term borrowings (including current maturities of
     long-term debt and other financing obligations)........      369     1,410
  Liabilities from price risk management activities.........      248       213
  Notes payable to affiliates...............................    2,374        --
  Income taxes payable......................................       13       198
  Other.....................................................      448       432
                                                              -------   -------
          Total current liabilities.........................    5,161     5,780
                                                              -------   -------
Debt
  Long-term debt............................................    4,985     5,107
                                                              -------   -------
Other liabilities
  Liabilities from price risk management activities.........       26         1
  Deferred income taxes.....................................    1,753     1,735
  Other.....................................................      355       579
                                                              -------   -------
                                                                2,134     2,315
                                                              -------   -------
Commitments and contingencies
Securities of subsidiaries
  Preferred interests of consolidated subsidiaries..........      400       750
  Minority interests in consolidated subsidiaries...........      253       144
                                                              -------   -------
                                                                  653       894
                                                              -------   -------
Stockholder's equity
  Common stock, par value $1 per share; authorized and
     issued 1,000 shares....................................       --        --
  Additional paid-in capital................................    1,339     1,305
  Retained earnings.........................................    3,102     3,385
  Accumulated other comprehensive income (loss).............     (141)      280
                                                              -------   -------
          Total stockholder's equity........................    4,300     4,970
                                                              -------   -------
          Total liabilities and stockholder's equity........  $17,233   $19,066
                                                              =======   =======
</Table>

                            See accompanying notes.

                                        47
<PAGE>

                              EL PASO CGP COMPANY

                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                                 (IN MILLIONS)

<Table>
<Caption>
                                                                YEAR ENDED DECEMBER 31,
                                                              ---------------------------
                                                               2002      2001      2000
                                                              -------   -------   -------
<S>                                                           <C>       <C>       <C>
Cash flows from operating activities
 Net income (loss)..........................................  $  (283)  $  (188)  $   654
   Less net loss from discontinued operations, net of income
     taxes..................................................     (124)       (5)       (1)
                                                              -------   -------   -------
 Net income (loss) from continuing operations...............     (159)     (183)      655
 Adjustments to reconcile net income (loss) to net cash from
   operating activities
   Depreciation, depletion and amortization.................      681       698       642
   Ceiling test charges.....................................      245       115        --
   Undistributed (earnings) loss from unconsolidated
     affiliates.............................................       43      (106)      (19)
   Deferred income tax expense (benefit)....................       11       (24)      203
   (Gains) Losses on long-lived assets......................      791       175        (5)
   Extraordinary items......................................       --        11        --
   Cumulative effect of accounting changes..................      (14)       --        --
   Non-cash gains from trading and power restructuring
     activities.............................................     (422)       --        --
   Non-cash portion of merger-related costs and changes in
     estimates..............................................       --     1,007        --
   Other non-cash income items..............................       --        27        (9)
   Working capital changes, net of non-cash transactions
     Accounts and notes receivable..........................     (157)     (599)     (470)
     Accounts payable.......................................     (940)      557       184
     Inventory..............................................       43       405      (138)
     Changes in trading price risk management activities....      (86)       67       (29)
     Other working capital changes
       Assets...............................................       90      (344)      119
       Liabilities..........................................       10       (35)      (52)
   Non-working capital changes
     Assets.................................................      127       541       (55)
     Liabilities............................................      (98)     (367)      108
                                                              -------   -------   -------
   Cash provided by continuing operations...................      165     1,945     1,134
   Cash provided by discontinued operations.................       90         7         5
                                                              -------   -------   -------
       Net cash provided by operating activities............      255     1,952     1,139
                                                              -------   -------   -------
Cash flows from investing activities
 Additions to property, plant and equipment.................   (1,705)   (2,245)   (2,043)
 Equity investments.........................................      (45)     (133)     (286)
 Net proceeds from the sale of assets.......................    1,650       268        59
 Net proceeds from the sale of investments..................      179       363        59
 Net change in restricted cash..............................      (43)       --        --
 Repayment of notes receivable from unconsolidated
   affiliates...............................................     (102)       20        --
 Net cash (paid) received for acquisitions, net of cash
   acquired.................................................       45      (232)       --
 Other......................................................      (64)        1        (1)
                                                              -------   -------   -------
   Cash used in continuing operations.......................      (85)   (1,958)   (2,212)
   Cash used in discontinued operations.....................      (12)      (56)      (69)
                                                              -------   -------   -------
       Net cash used in investing activities................      (97)   (2,014)   (2,281)
                                                              -------   -------   -------
Cash flows from financing activities
 Net proceeds (repayments) under commercial paper and
   short-term credit facilities.............................      (30)     (765)      217
 Issuances of common stock..................................       --         2        31
 Net proceeds from the issuance of long-term debt and other
   financing obligations....................................      882       490     1,722
 Payments to retire long-term debt and other financing
   obligations..............................................   (1,791)     (608)     (738)
 Payments to minority interest holders......................     (160)       --        --
 Payments to preferred interest holders.....................     (350)       --        --
 Dividends paid.............................................       --       (13)      (54)
 Net proceeds from issuance of minority interests in
   subsidiaries.............................................       33       139        --
 Net change in notes payable to unconsolidated affiliates...      (56)       --        --
 Net change in affiliated advances payable..................    1,317       889        --
 Contributions from (distributions to) discontinued
   operations...............................................       68       (43)      (65)
 Other......................................................       (6)        6        --
                                                              -------   -------   -------
   Cash provided by (used in) continuing operations.........      (93)       97     1,113
   Cash provided by (used in) discontinued operations.......      (68)       43        65
                                                              -------   -------   -------
       Net cash provided by (used in) financing
       activities...........................................     (161)      140     1,178
                                                              -------   -------   -------
Change in cash and cash equivalents.........................       (3)       78        36
 Less change in cash and cash equivalents related to
   discontinued operations..................................       10        (6)        1
                                                              -------   -------   -------
 Change in cash and cash equivalents from continuing
   operations...............................................      (13)       84        35
Cash and cash equivalents
 Beginning of period........................................      141        57        22
                                                              -------   -------   -------
 End of period..............................................  $   128   $   141   $    57
                                                              =======   =======   =======
</Table>

                            See accompanying notes.

                                        48
<PAGE>

                              EL PASO CGP COMPANY

                CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY
   (IN THOUSANDS OF SHARES AND MILLIONS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)

<Table>
<Caption>
                                                                             YEAR ENDED DECEMBER 31,
                                                              ------------------------------------------------------
                                                                   2002               2001                2000
                                                              ---------------   -----------------   ----------------
                                                              SHARES   AMOUNT    SHARES    AMOUNT   SHARES    AMOUNT
                                                              ------   ------   --------   ------   -------   ------
<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: Beginning balance........................     --    $  --          52   $  --         53   $   --
  Converted to common stock.................................                                             (1)      --
  Converted to El Paso common stock.........................                         (52)     --
                                                               ----    ------   --------   ------   -------   ------
        Ending balance......................................     --       --          --      --         52       --
                                                               ====    ======   ========   ======   =======   ======
  $1.83, Series B: Beginning balance........................     --       --          51      --         58       --
  Converted to common stock.................................                                             (7)      --
  Converted to El Paso common stock.........................                         (51)
                                                               ----    ------   --------   ------   -------   ------
        Ending balance......................................     --       --          --      --         51       --
                                                               ====    ======   ========   ======   =======   ======
  $5.00, Series C: Beginning balance........................     --       --          26      --         27       --
  Converted to common stock.................................                                             (1)      --
  Converted to El Paso common stock.........................                         (26)     --
                                                               ----    ------   --------   ------   -------   ------
        Ending balance......................................     --       --          --      --         26       --
                                                               ====    ======   ========   ======   =======   ======
Class A common stock, par value 33 1/3c per share,
  authorized 2,700 shares
  Beginning balance.........................................     --       --         311      --        345       --
  Converted to common stock.................................                                            (35)      --
  Conversion of preferred stock and exercise of stock
    options.................................................                                              1       --
  Converted to El Paso common stock.........................                        (311)     --
                                                               ----    ------   --------   ------   -------   ------
        Ending balance......................................     --       --          --      --        311       --
                                                               ====    ======   ========   ======   =======   ======
Common stock, par value 33 1/3c per share, authorized
  500,000 shares
  Beginning balance.........................................      1       --     219,605      73    217,705       72
  Exercise of stock options.................................                          86      --      1,793        1
  Conversion to El Paso common stock........................                    (219,690)    (73)
  Other.....................................................                                            107       --
                                                               ----    ------   --------   ------   -------   ------
        Ending balance......................................      1       --           1      --    219,605       73
                                                               ====    ======   ========   ======   =======   ======
Additional paid-in capital
  Beginning balance.........................................           1,305               1,044               1,032
  Merger-related equity exchange............................                                 (59)
  Capital contribution from El Paso.........................              32                 278
  Tax reallocation..........................................               2                  36
  Other.....................................................                                   6                  12
                                                                       ------              ------             ------
        Ending balance......................................           1,339               1,305               1,044
                                                                       ======              ======             ======
Retained earnings
  Beginning balance.........................................           3,385               3,573               2,973
  Net income (loss) for period..............................            (283)               (188)                654
  Dividends on common stock, 25c per share in 2000..........                                                     (54)
                                                                       ------              ------             ------
        Ending balance......................................           3,102               3,385               3,573
                                                                       ======              ======             ======
Accumulated other comprehensive income (loss)
  Beginning balance.........................................             280                  (8)                 (8)
  Other comprehensive income (loss).........................            (421)                288                  --
                                                                       ------              ------             ------
        Ending balance......................................            (141)                280                  (8)
                                                                       ======              ======             ======
Treasury stock, at cost
  Beginning balance.........................................     --       --      (4,395)   (132)    (4,396)    (132)
  Retirement of treasury shares.............................                       4,395     132
  Other.....................................................                                              1       --
                                                               ----    ------   --------   ------   -------   ------
        Ending balance......................................     --       --          --      --     (4,395)    (132)
                                                               ====    ------   ========   ------   =======   ------
        Total...............................................           $4,300              $4,970             $4,550
                                                                       ======              ======             ======
</Table>

                            See accompanying notes.

                                        49
<PAGE>

                              EL PASO CGP COMPANY

                CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
                                 (IN MILLIONS)

<Table>
<Caption>
                                                              YEAR ENDED DECEMBER 31,
                                                              -----------------------
                                                               2002     2001    2000
                                                              ------   ------   -----
<S>                                                           <C>      <C>      <C>
Net income (loss)...........................................  $(283)   $(188)   $654
                                                              -----    -----    ----
  Foreign currency translation adjustments..................    (12)     (30)     --
  Pension minimum liability accrual (net of income tax of
     $7)....................................................    (12)      --      --
  Unrealized net gains (losses) from cash flow hedging
     activities
     Cumulative-effect transition adjustment (net of income
      tax of $248)..........................................     --     (459)     --
     Unrealized mark-to-market gains (losses) arising during
      period (net of income tax of $140 in 2002 and $398 in
      2001).................................................   (241)     727      --
     Reclassification adjustments for changes in initial
      value to settlement date (net of income tax of $86 in
      2002 and $26 in 2001).................................   (156)      50      --
                                                              -----    -----    ----
       Other comprehensive income (loss)....................   (421)     288      --
                                                              -----    -----    ----
Comprehensive income (loss).................................  $(704)   $ 100    $654
                                                              =====    =====    ====
</Table>

                            See accompanying notes.

                                        50
<PAGE>

                              EL PASO CGP COMPANY

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. 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 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 as part of new accounting principles 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 U.S. generally
accepted accounting principles 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 natural gas pipelines are subject to the jurisdiction of the FERC in
accordance with the Natural Gas Act of 1938 and Natural Gas Policy Act of 1978.
We discontinued the application of regulatory accounting principles under
Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the
Effects of Certain Types of Regulation in 1996. SFAS No. 71 provides that rate
regulated enterprises account for and report assets and liabilities consistent
with the economic effect of the way in which regulators establish rates, if
those rates are designed to recover the costs of providing the regulated service
and if it is reasonable to assume that those rates can be charged and collected.
While our rates are designed to recover our costs, our ability to extend or
re-market expiring contracts is highly dependent on competitive alternatives at
the time these contracts are extended or expire. Currently, a substantial
portion of our revenues are under contracts that are discounted at rates below
the maximum rates. We will continue to evaluate the application of regulatory
accounting principles based on on-going changes in the regulatory and economic
environment and further actions in current and future rate cases or settlements.

  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 other current or non-current assets in our balance
sheet based on when we expect this cash to be used. As of December 31, 2002, we
reported $28 million and $32 million as other current assets and other
non-current current assets. As of December 31, 2001, we reported $17 million as
a current asset.

                                        51
<PAGE>

  Allowance for Doubtful Accounts

     We establish provisions for losses on accounts 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 refined products, crude oil and chemicals,
materials and supplies, natural gas in storage and coal. We also hold power
turbines in inventory. We classify inventory as current or non-current based on
whether it will be sold or used in the next twelve months. We report non-current
inventory as part of other non-current assets in our balance sheets. We use the
first-in, first-out and the average cost methods to account for our refined
products, crude oil and chemicals inventories and the average cost method to
account for our other inventories. We value all inventory at the lower of its
cost or market value.

  Natural Gas and Oil Imbalances and Exchanges

     Natural gas and oil imbalances occur when the actual amount of natural gas
or oil delivered from or received by a pipeline system, processing plant or
storage facility differs from the contractual amount scheduled to be delivered
or received. Natural gas exchange transactions involve receiving or delivering
natural gas that will be made up in-kind. We value these imbalances and
exchanges due to or from shippers and operators at an appropriate market index
price. Imbalances and exchanges are settled in cash or made up in-kind, subject
to the contractual terms of settlement and tariffs.

     Imbalances and exchanges due from others are reported in our balance sheet
as either accounts receivable from customers or accounts receivable from
unconsolidated affiliates. Imbalances and exchanges owed to others are reported
on the balance sheet as either trade accounts payable or accounts payable to
unconsolidated affiliates. In addition, all imbalances and exchanges are
classified as current or long-term depending on when we expect to settle them.

  Property, Plant and Equipment

     Our property, plant and equipment is recorded at its original cost of
construction or, upon acquisition, at either the fair value of the assets
acquired or the cost to the entity that first placed the asset in service. We
capitalize direct costs, such as labor and materials, and indirect costs, such
as overhead and interest. 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, remaining useful lives and depreciation rate:

<Table>
<Caption>
                                                              REMAINING USEFUL
                    TYPE                          METHOD           LIVES           RATES
---------------------------------------------  -------------  ----------------   ----------
                                                                 (IN YEARS)
<S>                                            <C>            <C>                <C>
Pipeline and storage systems.................  Straight-line        2-60          1% to 25%
Refining, crude oil and chemical                                    1-33
  facilities.................................  Straight-line                      3% to 20%
Power facilities.............................  Straight-line        5-19          5% to 33%
Gathering and processing systems.............  Straight-line        1-40          3% to 25%
Transportation equipment.....................  Straight-line         1-5         10% to 33%
Buildings and improvements...................  Straight-line        1-43          2% to 50%
Office and miscellaneous equipment...........  Straight-line         1-7          3% to 33%
</Table>

     When we retire facilities, we reduce property, plant and equipment for its
original cost, less accumulated depreciation, and salvage value. Any remaining
gain or loss is recorded in income.

     We capitalize a carrying cost on funds invested in our construction of
long-lived assets. This carrying cost includes an interest cost on the
investment financed by debt (capitalized interest). The capitalized interest is

                                        52
<PAGE>

calculated based on our average cost of debt. Amounts capitalized during the
years ended December 31, 2002, 2001 and 2000, were $18 million, $36 million and
$55 million. These amounts are included as a reduction of interest expense in
our income statements. Capitalized carrying costs for debt is reflected as an
increase in the cost of the asset on the 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 a long-lived asset's carrying value may not be recovered. These
events include market declines, changes in the manner in which we intend to use
an asset or decisions to sell an asset and adverse changes in the legal or
business environment such as adverse actions by regulators. 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. We also reclassify the asset or assets as either held for sale or as
discontinued operations, depending on whether they have independently
determinable cash flows.

  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, exploration and
development 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 and capitalized
interest.

     We amortize these costs using the unit of production method over the life
of our proved reserves. Each quarter, we calculate the unit of production
depletion rate based on our estimated production and an estimate of proved
reserves. Capitalized costs associated with unproved properties are excluded
from amortizable costs until these properties are evaluated. Future development
costs and dismantlement, restoration and abandonment costs, net of estimated
salvage values, are included in costs subject to amortization.

     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 statements as a ceiling test charge. Our ceiling test calculations
include the effects of derivative instruments we have designated as cash flow
hedges of our anticipated future natural gas and oil production.

     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.

  Planned Major Maintenance

     Repair and maintenance costs are generally expensed as incurred, unless
they improve the operating efficiency or extend the useful life of an asset.

     In our domestic refining business, repair and maintenance costs for planned
major maintenance activities are accrued as a liability in a systematic and
rational manner over the period of time until the planned major maintenance
activities occur. Any difference between the accrued liability and the actual
costs incurred in performing the maintenance activities are charged or credited
to expense at the time the maintenance occurs. At our international refineries,
the cost of each major maintenance activity is capitalized and amortized to
expense in a systematic and rational manner over the estimated period extending
to the next planned major maintenance activity. The types of costs we accrue in
conjunction with major maintenance at our refineries are outside contractor
costs, materials and supplies, company labor and other outside services. For our
domestic

                                        53
<PAGE>

operations, we had accruals for major maintenance of $40 million and $36 million
at December 31, 2002 and 2001, and for our international operations, we
capitalized $75 million and $51 million for the years ended December 31, 2002
and 2001.

  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 is not amortized and is periodically tested for
impairment, at least annually, or whenever an event occurs that indicates that
an impairment may have occurred. We adopted these standards on January 1, 2002
and stopped amortizing goodwill.

     SFAS No. 142 requires that we perform impairment tests upon adoption of the
standard on January 1, 2002 and at least annually thereafter. The initial
impairment tests we performed as of January 1, 2002 indicated no impairment of
goodwill. The impairment tests we performed as of December 31, 2002, however,
indicated a pre-tax impairment of goodwill associated with our Field Services
segment of $14 million. This impairment was recorded in 2002 and was primarily
the result of the sale of assets in the Field Services segment during 2002 and
early 2003. The net carrying amounts of our goodwill as of January 1, 2002 and
December 31, 2002 reported in net intangible assets in our balance sheets, and
the changes in the net carrying amounts of goodwill for the year ended December
31, 2002 for each of our segments are as follows:

<Table>
<Caption>
                                                                          FIELD     MERCHANT
                                                PIPELINES   PRODUCTION   SERVICES    ENERGY    TOTAL
                                                ---------   ----------   --------   --------   ------
                                                                    (IN MILLIONS)
<S>                                             <C>         <C>          <C>        <C>        <C>
Balances as of January 1, 2002................    $413         $61         $ 15       $--      $  489
Impairments...................................      --          --          (14)       --         (14)
Other changes.................................      --           1           --        --           1
                                                  ----         ---         ----       ---      ------
Balances as of December 31, 2002..............    $413         $62         $  1       $--      $  476
                                                  ====         ===         ====       ===      ======
</Table>

     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>
                                                              2002    2001
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
Intangible assets subject to amortization...................  $ 34    $ 34
Accumulated amortization....................................   (12)     (5)
                                                              ----    ----
                                                              $ 22    $ 29
                                                              ====    ====
</Table>

     Amortization expense of our intangible assets that were subject to
amortization was $7 million for the year ended December 31, 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 $2
million for each of the next five years. These amounts may vary as a result of
future acquisitions, dispositions and any recorded impairments.

     The following table presents our income (loss) from continuing operations
before extraordinary items and cumulative effect of accounting changes and net
income (loss) for the years ended December 31, 2001 and

                                        54
<PAGE>

2000, as if goodwill had not been amortized during those periods, compared with
those amounts reported for the years ended December 31, 2002:

<Table>
<Caption>
                                                                 YEAR ENDED DECEMBER 31,
                                                              ------------------------------
                                                                2002       2001       2000
                                                              --------   --------   --------
                                                                      (IN MILLIONS)
<S>                                                           <C>        <C>        <C>
Reported income (loss) from continuing operations before
  extraordinary items and cumulative effect of accounting
  changes...................................................   $(173)     $(172)      $655
Amortization of goodwill and indefinite-lived intangibles...      --         16         15
                                                               -----      -----       ----
Adjusted income (loss) from continuing operations before
  extraordinary items and cumulative effect of accounting
  changes...................................................   $(173)     $(156)      $670
                                                               =====      =====       ====
Net income (loss):
Reported net income (loss)..................................   $(283)     $(188)      $654
Amortization of goodwill and indefinite-lived intangibles...      --         16         15
                                                               -----      -----       ----
Adjusted net income (loss)..................................   $(283)     $(172)      $669
                                                               =====      =====       ====
</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 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 adjust this 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 and sales under gas sales contracts. For our
transportation and storage services, we recognize reservation revenue on firm
contracted capacity ratably over the contract period. For interruptible or
volumetric based services, 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 under natural gas sales
contracts are recognized when physical deliveries of commodities are made at the
agreed upon delivery point. 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 possibly be refunded in a final order of a pending or
future rate proceeding or as a result of a rate settlement. We have established
reserves for these potential refunds.

     Production revenues.  Our Production segment's revenues are derived
principally 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 product. When actual natural gas sales volumes exceed
our entitled share of sales volumes, an overproduced

                                        55
<PAGE>

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 gathering, transportation and processing 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.  Merchant Energy derives revenues from a number
of sources including physical sales of natural gas, power and petroleum, and
petroleum products. Revenues on these physical sales are recognized based on the
volumes delivered and the contracted or market price and are recognized at the
time the commodity is delivered to the specified delivery point. Revenues from
commodities sold as part of Merchant Energy's energy trading division are
reflected net of the cost of these sales. The energy trading division of
Merchant Energy also enters into derivative transactions which are recorded at
their fair value. See a discussion of our income recognition policies on
derivatives below under Price Risk Management Activities.

     Corporate.  During 2000 and 2001 our corporate segment owned retail gas
stations. These were sold during 2001. We recognized revenues from these
activities when products and services were delivered to our retail customers.

  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 inflation and 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

     We engage in price risk management activities to manage market risks
associated with commodities we purchase and sell, interest rates and foreign
currency exchange rates. These price risk management activities include trading
activities that we enter into with the objective of generating profits or from
exposure to shifts or changes in market prices, non-trading activities related
to our power investment, generation and power contract restructuring activities,
and other non-trading activities that involve hedging the market price risk
exposures on our assets, liabilities, contractual commitments and forecasted
transactions of each of our business segments. Our trading and non-trading price
risk management activities involve the use of a variety of derivative financial
instruments, including:
                                        56
<PAGE>

     - exchange-traded fixtures contracts that involve cash settlements;

     - forward contracts that involve cash settlements or physical delivery of a
       commodity;

     - swap contracts that require payments to (or receipts from) counterparties
       based on the difference between a fixed and a variable price, or two
       variable prices, for a commodity; and

     - exchange-traded and over-the-counter options.

     We account for our trading and non-trading derivative instruments under
SFAS No. 133, Accounting for Derivatives and Hedging Activities. Under SFAS No.
133, all derivatives are reflected in our balance sheet at their fair value as
price risk management activities. We classify our price risk management
activities as either current or non-current assets or liabilities based on our
overall position by counterparty and their anticipated settlement date. Cash
inflows and outflows associated with the settlement of our price risk management
activities are recognized in operating cash flows, and any receivables and
payables resulting from these settlements are reported separately from price
risk management activities in our balance sheet as trade receivables and
payables. The accounting for revenues and expenses associated with our price
risk management activities varies based on whether those activities are trading
activities or non-trading activities. See Note 11 for a further description of
our price risk management activities.

     During 2002, we adopted 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 a gain of $14
million, net of income taxes, as a cumulative effect of an accounting change in
our income statement for our proportionate share of this gain.

     During 2002, we also adopted the provisions of EITF Issue 02-3, Issues
Related to Accounting for Contracts Involved in Energy Trading and Risk
Management Activities. EITF Issue 02-3 requires that all revenues and costs
associated with trading activities should be shown net in the income statement,
whether or not they are physically settled. We began to report our trading
activity on a net basis (revenues net of the expenses of the physically settled
purchases) as a component of revenues effective July 1, 2002. We applied this
guidance to all prior periods, which had no impact on previously reported net
income or stockholder's equity. Revenues and costs for periods prior to the
adoption of EITF Issue No. 02-3 are revised as follows:

<Table>
<Caption>
                                                              YEAR ENDED DECEMBER 31,
                                                              -----------------------
                                                                 2001         2000
                                                              ----------   ----------
                                                                   (IN MILLIONS)
<S>                                                           <C>          <C>
Gross operating revenues....................................   $ 25,369     $ 26,660
Costs reclassified..........................................    (16,645)     (11,044)
                                                               --------     --------
  Net operating revenues reported in the income
     statements.............................................   $  8,724     $ 15,616
                                                               ========     ========
</Table>

  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
income tax return. The policy provides, among other things, that (i) each
company in a taxable income position will accrue a current expense equivalent to
its federal income tax, and (ii) each company in a tax loss position will accrue
a benefit to the extent its deductions, including general

                                        57
<PAGE>

business credits, can be utilized in the consolidated return. El Paso pays all
federal income taxes directly to the IRS and, under a separate tax billing
agreement, El Paso may bill or refund its subsidiaries for their portion of
these income tax payments. Prior to the 2001 tax return, we filed a separate tax
return and were not subject to El Paso's tax accrual policy.

  Excise Taxes

     In our refining and marketing operations, we do not record the amounts of
excise taxes we bill and collect from customers in revenues. Rather, we record a
receivable from our customers and a payable to the government agencies or
suppliers.

     In our retail business, we sold substantially all of our retail gas
stations in 2001. During 2001 and 2000, we accounted for excise taxes by
recording amounts billed to customers in operating revenues with a corresponding
entry for amounts owed in operating expenses. As of December 31, 2001 and 2000,
we recorded approximately $69 million and $198 million in excise taxes related
to our retail activities.

  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. 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 of interest expense. The net currency loss recorded in operating
income was insignificant in 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 comprehensive income and stockholders' equity. The cumulative
currency translation loss recorded in accumulated other comprehensive income was
$50 million and $38 million at December 31, 2002 and 2001. Revenues and expenses
are translated at average exchange rates prevailing during the year.

  Accounting for Debt Extinguishments

     We apply the provisions of SFAS No. 145, Rescission of FASB Statements No.
4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections to
account for debt extinguishments. Under SFAS No. 145, we are required to
evaluate any gains or losses incurred when we retire debt early to determine
whether they are extraordinary in nature or whether they should be included as
ordinary income from continuing operations in the income statement. In the third
quarter of 2002, we retired debt totaling $10 million, which resulted in a gain
of $1 million. Because we believe that we will continue to retire debt in the
near term, we reported this gain as income from continuing operations, as part
of other income.

  New Accounting Pronouncements Issued But Not Yet Adopted

     As of December 31, 2002, there were a number of accounting standards and
interpretations that had been issued but not yet adopted by us. Below is a
discussion of the more significant standards that could impact us.

     Accounting for Asset Retirement Obligations.  In June 2001, the Financial
Accounting Standards Board (FASB) issued SFAS No. 143, Accounting for Asset
Retirement Obligations. This statement requires companies to record a liability
for the estimated retirement and removal costs of long-lived assets used in
their business. The liability is recorded at its fair value, with a
corresponding asset which is depreciated over the remaining useful life of the
long-lived asset to which the liability relates. An ongoing expense will also be
recognized for changes in the value of the liability as a result of the passage
of time. The provisions of SFAS No. 143 are effective for fiscal years beginning
after June 15, 2002. We expect that we will record a charge as a cumulative
effect of accounting change of approximately $21 million, net of income taxes,
upon our adoption of SFAS No. 143 on January 1, 2003. We also expect to record
non-current retirement assets of $106 million

                                        58
<PAGE>

and non-current retirement liabilities of $135 million on January 1, 2003. Our
liability relates primarily to our obligations to plug abandoned wells in our
Production and Pipelines segments over the next four to 24 years.

     Accounting for Costs Associated with Exit or Disposal Activities.  In July
2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or
Disposal Activities. This statement will require us to recognize costs
associated with exit or disposal activities when they are incurred rather than
when we commit to an exit or disposal plan. Examples of costs covered by this
guidance include lease termination costs, employee severance costs associated
with a restructuring, discontinued operations, plant closings or other exit or
disposal activities. the statement is effective for fiscal years beginning after
December 31, 2002, and will impact any exit or disposal activities we initiate
after January 1, 2003.

     Accounting for Guarantees.  In November 2002, the FASB issued FASB
Interpretation (FIN) No. 45, Guarantor's Accounting and Disclosure Requirements
for Guarantees, Including Indirect Guarantees of Indebtedness of Others. This
interpretation requires that companies record a liability for all guarantees
issued after January 31, 2003, including financial, performance, and fair value
guarantees. This liability is recorded at its fair value upon issuance, and does
not affect any existing guarantees issued before January 31, 2003. This standard
also requires expanded disclosures on all existing guarantees at December 31,
2002. We have included these required disclosures in Note 16.

     Consolidation of Variable Interest Entities.  In January 2003, the FASB
issued 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 that companies 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. The provisions of FIN No. 46 are effective for all variable
interest entities created after January 31, 2003, and are effective on July 1,
2003 for all variable interest entities created before January 31, 2003. We have
financial interests in several entities that we anticipate will be considered
variable interest entities. They fall into two categories:

     - Operating leases with residual value guarantees;

     - Consolidated subsidiaries with preferred interests held by third party
       financial investors.

     Operating leases with residual value guarantees.  We have an operating
lease on a facility at our Aruba refinery where we provide a guarantee to the
lessor for the residual value of the facilities that we lease.

     We believe we will consolidate the lessor under this arrangement on July 1,
2003 because (i) the equity investment by the third party investors (which are
banks) is less than 10 percent of the total capitalization of the company that
leases the facility to us, and (ii) because we guarantee a significant portion
of the funds that were borrowed by the lessor to buy the facilities from us.
When we consolidate the lessor of this facility, the assets owned by the lessor
and the debt that supports the assets will be consolidated in our financial
statements. In addition, these assets, once consolidated, will be subject to
impairment testing under SFAS No. 144. Based on our preliminary analysis, we
believe the impact on our financial statements will be to increase our total
assets and long-term debt by approximately $350 million.

     Consolidated subsidiaries with preferred interests held by third party
investors.  We currently have interests in and consolidate an entity in which
third party investors hold preferred interests. The preferred interests held by
the third party investors are reflected in our balance sheet as preferred
securities in consolidated subsidiaries. The third party investors are
capitalized with three percent equity, which is held by banks in these
arrangements, and 97 percent debt. We believe we would consolidate these third
party investors under these arrangements because (i) the equity investment in
these third party investors is less than the specified 10 percent of total
capitalization of the investors and (ii) the right of the third party investors
to expected residual returns from these arrangements is limited. When we
consolidate these third party investors, the minority interest that is currently
classified as preferred securities in consolidated subsidiaries will be

                                        59
<PAGE>

classified as long-term debt. Coastal Securities Company Limited is our
consolidated subsidiary that will be impacted by this standard. We believe the
impact on our financial statements will be (in millions):

<Table>
<S>                                                            <C>
Decrease in preferred securities of consolidated
  subsidiaries..............................................       $100
Increase in long-term debt..................................       $100
</Table>

     For a further discussion of the consolidated subsidiaries potentially
impacted by this pronouncement, see Note 15.

2. MERGER AND DIVESTITURES

  Merger with El Paso Corporation

     In January 2001, we merged with El Paso Corporation (El Paso). In the
merger, holders of our common stock and Class A common stock received 1.23
shares of El Paso common stock for each outstanding common share; holders of our
Series A and Series B convertible preferred stock received 9.133 shares of El
Paso common stock for each outstanding convertible preferred share; and holders
of our Series C convertible preferred stock received 17.98 shares of El Paso
common stock for each outstanding convertible preferred share. All these
exchanges were done on a tax free basis. In addition, holders of our outstanding
stock options received shares of El Paso common stock based on the fair value of
these options on the date of the merger. As a result of the merger, El Paso owns
100 percent of our common equity.

  Divestitures

     During 2002 and 2003, we have completed or announced a number of asset
sales in order to rationalize our business and address liquidity issues and
changing market conditions. These sales occurred in all of our business segments
as follows.

<Table>
<Caption>
                            PRETAX GAIN
SEGMENT          PROCEEDS     (LOSS)              SIGNIFICANT ASSETS AND INVESTMENTS SOLD
-------          --------   -----------    -----------------------------------------------------
                     (IN MILLIONS)
<S>              <C>        <C>            <C>
Completed in 2002
Pipelines         $  303       $   4       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        (702)(1)   Natural gas and oil properties located in:
                                             South Texas
                                             Colorado
                                             Southeast Texas
                                             Utah
                                             Western Canada
Field Services       120         (14)      Dragon Trail processing plant
                                           14.4 percent equity interest in Aux Sable NGL plant
                                           Gathering facilities located in Utah
                                           50 percent equity interest in Blacks Fork facility
Merchant Energy       71          (3)      50 percent equity interest in petroleum products
                                           terminal
                                           NGL pipelines and fractionation facilities
                                           14.4 percent equity interest in Alliance Canada
                                             Marketing L.P.
                                           Typhoon oil pipeline
Other                 57          --       Coal reserves and properties in West Virginia,
                                             Virginia and Kentucky(2)
                  ------       -----
                  $1,848       $(715)
                  ======       =====
</Table>

                                        60
<PAGE>

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

(1) We recognized a loss of $702 million, or $452 million net of income tax, on
    the sale of natural gas and oil properties in Utah. A loss was recognized on
    this sale because the reserves sold significantly altered the relationship
    between capitalized costs and proved reserves. We did not, however,
    recognize gains or losses on the remaining completed sales of natural gas
    and oil properties because individually they did not alter the relationship
    between capitalized costs and proved reserves at the time they were sold.

(2) During 2002, we recorded impairment charges of $185 million since the
    carrying value was higher than our estimated net sales proceeds. These
    properties are presented in our financial statements as discontinued
    operations. See Note 9 for further discussion.

<Table>
<Caption>
                            PRETAX GAIN
SEGMENT          PROCEEDS     (LOSS)              SIGNIFICANT ASSETS AND INVESTMENTS SOLD
-------          --------   -----------    -----------------------------------------------------
                     (IN MILLIONS)
<S>              <C>        <C>            <C>
Announced or completed in 2003 (amounts are estimates)(1)

Pipelines         $   43       $  (1)      Panhandle gathering system in Texas
                                           2.1 percent interest in Alliance pipeline and related
                                             assets

Production           178          --(2)    Natural gas and oil properties located in western
                                             Canada, New Mexico, Oklahoma and Mid-Continent
                                             region

Field Services        35          --       Gathering systems located in Wyoming

Merchant Energy      518          63       Corpus Christi refinery
                                           Florida petroleum terminals and tug and barge
                                           operations(3)
                                           Petroleum asphalt operations

Other                 59          --       Remaining coal reserves and properties in West
                                             Virginia, Virginia and Kentucky(4)
                  ------       -----
                  $  833       $  62
                  ======       =====
</Table>

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

(1) Sales that have been announced, but not completed, are subject to customary
    regulatory approvals and other conditions.
(2) We do not anticipate recognizing gains or losses on these sales of natural
    gas and oil properties because individually they will not significantly
    alter the relationship between capitalized costs and proved reserves at the
    time they are sold.
(3) The amount includes a $25 million receivable.
(4) Proceeds of $59 million consisted of $35 million in cash and $24 million in
    notes receivable.

     In December 2002, we classified several of Field Service's small gathering
systems located in Wyoming and Merchant Energy's Florida petroleum terminals and
tug and barge operations to assets held for sale. We also classified our
petroleum asphalt operations and lease crude business as held for sale. The
total assets being sold had a net book value in property, plant and equipment of
approximately $134 million. We reclassified these assets as other current assets
as of December 31, 2002, since we plan to sell them in the next twelve months.

     Under a Federal Trade Commission order, as a result of our January 2001
merger with El Paso, 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. For the year ended December
31, 2001, net proceeds from these sales were approximately $184 million. We
recognized extraordinary net losses of approximately $11 million, net of income
taxes of approximately $5 million.

     In February 2003, El Paso announced it would exit non-core businesses,
including substantially all of our petroleum business (except our Aruba
refinery). Since making this announcement, we have been identifying potential
buyers for our petroleum assets. At this time, we cannot determine the amount of
gain or loss, if any, that will be incurred. We will continue to evaluate
whether these assets will be treated for accounting purposes as assets held for
sale or possibly as discontinued operations.

                                        61
<PAGE>

3. RESTRUCTURING AND MERGER-RELATED COSTS

     During each of the years ended December 31, we incurred restructuring and
merger-related costs as follows:

<Table>
<Caption>
                                                               2002   2001   2000
                                                               ----   ----   ----
                                                                 (IN MILLIONS)
<S>                                                            <C>    <C>    <C>
Restructuring costs.........................................   $  5   $ --   $ --
Merger-related costs........................................     --    814     13
                                                               ----   ----   ----
                                                               $  5   $814   $ 13
                                                               ====   ====   ====
</Table>

  Restructuring Costs

     Our restructuring costs were incurred in connection with organizational
restructurings in connection with El Paso's balance sheet and liquidity
enhancement activities in 2002. In December 2001, El Paso announced a plan to
strengthen its balance sheet, reduce costs and focus its activities on its core
natural gas business. During 2002, we completed an employee restructuring across
all of our operating segments, which resulted in a reduction of approximately
156 full-time positions through terminations. Through December 31, 2002, in our
Merchant Energy segment, we had incurred and paid $5 million of employee
severance and termination costs in connection with these actions.

  Merger-Related Costs

     During the year ended 2001, we incurred merger-related costs in connection
with our merger with El Paso completed in January 2001 as follows:

<Table>
<Caption>
                                                                             FIELD     MERCHANT
                      2001                         PIPELINES   PRODUCTION   SERVICES    ENERGY    OTHER   TOTAL
                      ----                         ---------   ----------   --------   --------   -----   -----
                                                                          (IN MILLIONS)
<S>                                                <C>         <C>          <C>        <C>        <C>     <C>
       Employee severance, retention and
         transition costs........................    $ 76         $ 7         $ 2        $ 18     $480    $583
       Business and operational integration
         costs...................................      86          15          --          --       22     123
       Other.....................................      30          23          11          26       18     108
                                                     ----         ---         ---        ----     ----    ----
         Total merger-related costs..............    $192         $45         $13        $ 44     $520    $814
                                                     ====         ===         ===        ====     ====    ====
</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. Employee severance
costs include actual severance payments and costs for pension and
post-retirement benefits settled and curtailed under existing benefit plans as a
result of these restructurings. Retention charges include payments to employees
who were retained following the mergers and payments to employees to satisfy
contractual obligations. Transition costs relate to costs to relocate employees
and costs for severed and retired employees arising after their severance date
to transition their jobs into the ongoing workforce.

     Employee severance, retention, and transition costs for 2001 were
approximately $583 million which included pension and post-retirement benefits
of $214 million which were accrued at the merger date and will be paid over the
applicable benefit periods of the terminated and retired employees. All other
costs were expensed as incurred and have been paid. Also included in the 2001
employee severance, retention and transition costs was a charge of $278 million
resulting from the issuance of approximately 4 million shares of El Paso common
stock on the date of the 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.

                                        62
<PAGE>

     Business and operational integration costs include charges to consolidated
facilities and operations of our business segments. Total charges in 2001 were
$123 million. The charges include incremental fees under software and seismic
license agreements of $15 million, which were recorded in our Production
segment. Additional integration costs included approximately $108 million in
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. These charges were
incurred in both our Pipeline and Corporate segments. These charges were accrued
at the time we completed our relocations and closed these offices. The amounts
accrued will be paid over the term of the applicable non-cancelable lease
agreements. All other costs were expensed as incurred.

     Other costs for 2001 were $108 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.

     Merger-related costs incurred in 2000 were related to transaction costs,
which included investment banking, legal, accounting, consulting and other
advisory fees incurred to obtain federal and state regulatory approvals and take
other actions necessary to complete the merger. All of these items were expensed
in the periods in which they were incurred.

4.  GAIN (LOSS) ON LONG-LIVED ASSETS

     Gain (loss) on long-lived assets consist of realized gains and losses on
sales of long-lived assets and impairments of long-lived assets. During each of
the years ended December 31, our gains (losses) on long-lived assets were as
follows:

<Table>
<Caption>
                                                              2002    2001    2000
                                                              -----   -----   ----
                                                                 (IN MILLIONS)
<S>                                                           <C>     <C>     <C>
Realized gain (loss)........................................  $(650)  $  (7)  $ 18
Asset impairments...........................................   (141)   (168)   (13)
                                                              -----   -----   ----
Gain (loss) on long-lived assets............................  $(791)  $(175)  $  5
                                                              =====   =====   ====
</Table>

     Realized Gain (Loss)

     Our realized gain (loss) on sales of long-lived assets for the years ended
December 31, 2002, 2001 and 2000, were $(650) million, $(7) million and $18
million. Our 2002 loss was primarily a result of losses related to the sales of
natural gas and oil properties located in Utah in our Production segment, and
the sale of our Natural Buttes gathering system, our Ouray gathering system and
our Dragon Trail processing plant in our Field Services segment. See Note 2 for
a further discussion of these divestitures. Our 2001 losses related to
miscellaneous asset sales across all our segments and our 2000 gain related to
the sale of a portion of our Montreal paraxylene plant in our Merchant Energy
segment.

                                        63
<PAGE>

     Asset Impairments

     During the years ended December 31, we incurred asset impairment charges in
our business segments as follows:

<Table>
<Caption>
SEGMENT AND ASSET DESCRIPTION                     AMOUNT                    CAUSE OF IMPAIRMENT
-----------------------------                  -------------                -------------------
                                               (IN MILLIONS)
<S>                                            <C>             <C>
2002
Production
  Intangible asset...........................      $  4        Sale of underlying properties
                                                   ----
         Total Production....................         4
                                                   ----
Field Services
  Goodwill impairment........................        14        Sale of assets in the segment
                                                   ----
         Total Field Services................        14
                                                   ----
Merchant Energy
  MTBE chemical processing plant.............        91        MTBE was banned in our largest market.
                                                               Decision to eliminate future capital spending
                                                               to refit plant for alternative fuel uses
  Power turbines.............................        18        Scaled down capital spending in new power
                                                               facilities and weak economic conditions in
                                                               the power sector
  Solarc project.............................        14        Decision to discontinue future capital
                                                   ----        investment
         Total Merchant Energy...............       123
                                                   ----
         Total 2002 asset impairments........      $141
                                                   ====
2001
Pipelines
  Renaissance Center leasehold                     $  9        Relocation of Detroit headquarters
    improvements.............................
  Supply Link projects.......................         7        Decision following the El Paso merger not to
                                                               pursue these projects
  Other projects.............................         6        Decision following the El Paso merger not to
                                                   ----        pursue these projects
         Total Pipelines.....................        22
                                                   ----
Production
  Australian and Indonesian assets...........        16        Decision following the El Paso merger not to
                                                   ----        drill in these areas
         Total Production....................        16
                                                   ----
Merchant Energy
  Oyster Creek chemical facility.............        37        Facility shut down following the El Paso
                                                               merger
  Kansas refining operations.................        35        Refinery closed as a result of sale of retail
                                                               outlets in the midwest
  Capitalized development costs..............        20        Decision not to pursue projects following the
                                                               El Paso merger
  Other merchant assets......................        24        Change in strategy and business decisions
                                                               following merger
  Corpus Christi refinery....................         8        Lease of Corpus Christi refinery to Valero
                                                   ----        Energy Corporation
         Total Merchant Energy...............       124
                                                   ----
Corporate and Other
  Miscellaneous corporate assets.............         6        Relocation of Detroit headquarters
                                                   ----
         Total Corporate and Other...........         6
                                                   ----
         Total 2001 asset impairments........      $168
                                                   ====
2000
Merchant Energy
  Florida and other refining assets..........      $ 13        Decision not to pursue development on these
                                                               projects
         Total Merchant Energy...............        13
                                                   ----
         Total 2000 asset impairments........      $ 13
                                                   ====
</Table>

     Our impairment charges were based on reducing the carrying value of these
assets to their estimated fair value. Fair value was 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).

                                        64
<PAGE>

5. CHANGES IN ACCOUNTING ESTIMATES

     Included in our operation and maintenance costs for the twelve months ended
December 31, 2001 were 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 worldwide operations. The
change in our estimated environmental remediation liabilities was due to a
number of events including $109 million resulting from the sale of a majority of
our retail gas stations, $31 million related to our closure of our Gulf Coast
Chemical and Midwest refining operations, $10 million associated with the lease
of our Corpus Christi refinery to Valero, and $82 million associated with
conforming our methods of environmental identification, assessment and
remediation strategies and processes to El Paso's historical practices following
our merger with El Paso. This accounted for the remainder of the change in
estimated obligations. The change in estimate of our legal obligations was a
result of a review process to assess our legal exposures, strategies and plans
following the merger with El Paso. Finally, the charge related to our spare
parts inventories was primarily the result of several events that occurred as
part of and following our merger with El Paso, including the consolidation of
numerous operation locations, the sale of a majority of our retail gas stations,
the shutdown of our Midwest refining operations and the lease of our Corpus
Christi refinery. These changes were also a direct result of a fire at our Aruba
refinery whereby a portion of the plant was rebuilt following the fire rendering
many of these parts unusable. Also impacting these amounts was the evaluation of
the operating standards, strategies and plans of our combined company following
the merger. Our changes in estimates are included as operating expenses in our
income statement and reduced our net income before extraordinary items and net
income for the year ended December 31, 2001 by approximately $241 million.

6. CEILING TEST CHARGES

     Under the full cost method of accounting for natural gas and oil
properties, we perform quarterly ceiling tests to evaluate whether the carrying
value of natural gas and oil properties exceeds the present value of future net
revenues, discounted at 10 percent, plus the lower of cost or fair market value
of unproved properties, net of related income tax effects.

     For the year ended December 31, 2002, we recorded ceiling test charges of
$245 million, of which $10 million was charged during the first quarter, $233
million was charged during the second quarter, and $2 million was charged during
the fourth quarter. The write-down includes $226 million for our Canadian full
cost pool, $10 million for our Brazilian full cost pool and $9 million for other
international production operations, primarily in Australia. Our third quarter
charges were based on the daily posted natural gas and oil prices as of November
1, 2002, adjusted for oilfield or natural gas gathering hub and wellhead price
differences as appropriate. Had we computed the ceiling test charges based upon
the daily posted natural gas and oil prices as of September 30, 2002, we would
have incurred a charge of $96 million relating to our domestic full cost pool.
The charge for the Canadian full cost pool primarily resulted from a low daily
posted price for natural gas at June 30, 2002, which was approximately $1.43 per
MMbtu.

     For the year ended December 31, 2001, we recorded ceiling test charges of
$115 million, including $87 million for our Canadian full cost pool and $28
million for our Brazilian full cost pool. Our 2001 charges were based on the
daily posted natural gas and oil prices as of November 1, 2001, adjusted for
oilfield or natural gas gathering hub and wellhead price differences as
appropriate. Had we computed the third quarter 2001 ceiling test charges based
upon the daily posted natural gas and oil prices as of September 30, 2001, we
would have incurred a ceiling test charge of $255 million. This amount would
have included $227 million for our Canadian full cost pool and $28 million for
our Brazilian full cost pool.

     We use financial instruments to hedge against the volatility of natural gas
and oil prices. The impact of these hedges was considered in determining our
ceiling test charges, and will be factored into future ceiling test
calculations. Had the impact of our hedges not been included in calculating our
ceiling test charges, we would have incurred a charge of $125 million for the
nine months ended September 30, 2002, and $830 million for the nine months ended
September 30, 2001, relating to our domestic full cost pool. The charges for our

                                        65
<PAGE>

international cost pools would not have materially changed since we do not
significantly hedge our international production activities.

7. OTHER INCOME AND OTHER EXPENSES

     Following are the components of other income and other expenses for each of
the three years ended December 31:

<Table>
<Caption>
                                                              2002   2001   2000
                                                              ----   ----   ----
                                                                (IN MILLIONS)
<S>                                                           <C>    <C>    <C>
Other Income
  Favorable resolution of non-operating contingent
     obligations............................................  $ 31   $  4   $  5
  Property losses and insurance.............................    26     60     --
  Rental income.............................................    18     35     21
  Development, management and administrative services fees
     on power projects......................................    14     18     19
  Interest income...........................................    13     28     34
  Income from retail operations.............................    --      4     15
  Other.....................................................    16     41     32
                                                              ----   ----   ----
          Total                                               $118   $190   $126
                                                              ====   ====   ====
Other Expenses
  Miscellaneous balancing adjustments.......................  $ 13   $ 12   $ --
  Foreign currency loss.....................................     3      1     --
  Penalty and legal expenses................................     3      1     --
  Other.....................................................    18     14     10
                                                              ----   ----   ----
          Total                                               $ 37   $ 28   $ 10
                                                              ====   ====   ====
</Table>

8. INCOME TAXES

     Pretax income (loss) from continuing operations before extraordinary items
and cumulative effect of accounting change are composed of the following for
each of the three years ended December 31:

<Table>
<Caption>
                                                               2002     2001    2000
                                                              ------    -----   ----
                                                                  (IN MILLIONS)
<S>                                                           <C>       <C>     <C>
United States...............................................  $ (168)   $(129)  $723
Foreign.....................................................     (40)      38    185
                                                              ------    -----   ----
                                                              $ (208)   $ (91)  $908
                                                              ======    =====   ====
</Table>

                                        66
<PAGE>

     The following table reflects the components of income tax expense (benefit)
included in income (loss) from continuing operations before extraordinary items
and cumulative effect of accounting change for each of the three years ended
December 31:

<Table>
<Caption>
                                                              2002     2001   2000
                                                              -----    ----   ----
                                                                 (IN MILLIONS)
<S>                                                           <C>      <C>    <C>
Current
  Federal...................................................  $ (58)   $104   $ 42
  State.....................................................      2      (5)    (1)
  Foreign...................................................     10       6      9
                                                              -----    ----   ----
                                                                (46)    105     50
                                                              -----    ----   ----
Deferred
  Federal...................................................     68      28    189
  State.....................................................     44     (15)    11
  Foreign...................................................   (101)    (37)     3
                                                              -----    ----   ----
                                                                 11     (24)   203
                                                              -----    ----   ----
          Total income tax expense (benefit)................  $ (35)   $ 81   $253
                                                              =====    ====   ====
</Table>

     Our tax expense (benefit), included in income (loss) from continuing
operations before extraordinary items and cumulative effect of accounting
change, 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    2000
                                                              ----    ----    ----
                                                                 (IN MILLIONS)
<S>                                                           <C>     <C>     <C>
Tax expense (benefit) at the statutory federal rate of
  35%.......................................................  $(73)   $(32)   $318
Increase (decrease)
  Tight sands gas credit....................................    --      --      (6)
  State income taxes........................................    30     (13)      6
  Foreign income taxed at different tax rates...............    (2)     (2)    (48)
  Depreciation, depletion and amortization..................    --      20     (17)
  Goodwill impairment.......................................     5      --      --
  Non-deductible portion of merger costs and other tax
     adjustments to provide for revised estimated
     liabilities............................................    --     106      --
  Non-deductible dividends on preferred stock of
     subsidiaries...........................................     2       3       4
  Other.....................................................     3      (1)     (4)
                                                              ----    ----    ----
Income tax expense (benefit)................................  $(35)   $ 81    $253
                                                              ====    ====    ====
Effective tax rate..........................................    17%    (89)%    28%
                                                              ====    ====    ====
</Table>

                                        67
<PAGE>

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

<Table>
<Caption>
                                                               2002     2001
                                                              ------   ------
                                                               (IN MILLIONS)
<S>                                                           <C>      <C>
Deferred tax liabilities
  Property, plant and equipment.............................  $1,904   $1,771
  Investments in unconsolidated affiliates..................     216      255
  Price risk management activities..........................      --      173
  Other assets..............................................     108      507
                                                              ------   ------
          Total deferred tax liability......................   2,228    2,706
                                                              ------   ------
Deferred tax assets
  U.S. net operating loss and tax credit carryovers.........     217      256
  Environmental liability...................................      57       99
  Price risk management activities..........................      53       --
  Other liabilities.........................................     254      576
                                                              ------   ------
          Total deferred tax asset..........................     581      931
                                                              ------   ------
Net deferred tax liability..................................  $1,647   $1,775
                                                              ======   ======
</Table>

     At December 31, 2002, 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 $964 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.

     The tax benefit associated with the exercise of non-qualified stock options
and the vesting of restricted stock, as well as restricted stock dividends,
reduced taxes payable by $2 million in 2002, $5 million in 2001 (allocated to us
in both years under El Paso's tax accrual policy), and $18 million in 2000.
These benefits are included in additional paid-in capital in our balance sheets.

     As of December 31, 2002, we had alternative minimum tax credits of $217
million that carryover indefinitely. Usage of these carryovers is subject to the
limitations provided under Section 383 of the Internal Revenue Code as well as
the separate return limitation year rules of IRS regulations.

9. DISCONTINUED OPERATIONS

     In June 2002, our parent's Board of Directors authorized the sale of our
coal mining operations. These operations, which have historically been included
in our Merchant Energy segment, consist of fifteen active underground and two
surface mines located in Kentucky, Virginia and West Virginia. Following the
authorization of the sale by our parent's Board of Directors, 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 sale process in the
second and third quarters of 2002. Because this carrying value was higher than
our estimated net sales proceeds, we recorded impairment charges of $148 million
in the second quarter of 2002 and $37 million in the third quarter of 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 consists of mining operations, businesses, properties and
reserves in Kentucky, West Virginia and Virginia, to subsidiaries of Alpha
Natural Resources, LLC, an affiliate of First Reserve Corporation, for $59
million which includes $35 million in cash and $24 million in notes receivable.

                                        68
<PAGE>

     Our coal mining operations have been classified as discontinued operations
in our financial statements for all periods presented. In addition, we
reclassified all of the assets and liabilities of our remaining coal mining
operations as of December 31, 2002 to other current assets and liabilities. The
summarized financial results of discontinued operations for each of the three
years ended December 31, are as follows:

<Table>
<Caption>
                                                              2002    2001    2000
                                                              -----   -----   -----
                                                                  (IN MILLIONS)
<S>                                                           <C>     <C>     <C>
Operating Results:
  Revenues..................................................  $ 309   $ 277   $ 276
  Costs and expenses........................................   (327)   (286)   (270)
  Asset impairments.........................................   (185)     --      (8)
  Other income, net.........................................      6       2       1
                                                              -----   -----   -----
  Loss before income taxes..................................   (197)     (7)     (1)
  Income tax benefit........................................     73       2      --
                                                              -----   -----   -----
  Loss from discontinued operations, net of income taxes....  $(124)  $  (5)  $  (1)
                                                              =====   =====   =====
</Table>

<Table>
<Caption>
                                                              DECEMBER 31,
                                                              -------------
                                                              2002    2001
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
Financial Position Data:
  Assets of discontinued operations
     Accounts receivable....................................  $ 29    $ 35
     Inventory..............................................    14      11
     Property, plant and equipment, net.....................    46     301
     Other..................................................    17       5
                                                              ----    ----
       Total assets.........................................  $106    $352
                                                              ====    ====
  Liabilities of discontinued operations
     Accounts payable and other.............................  $ 25    $ 37
     Environmental remediation reserve......................    15      --
                                                              ----    ----
       Total liabilities....................................  $ 40    $ 37
                                                              ====    ====
</Table>

10. FINANCIAL INSTRUMENTS

     Following are the carrying amounts and estimated fair values of our
financial instruments as of December 31:

<Table>
<Caption>
                                                                 2002                    2001
                                                         ---------------------   ---------------------
                                                         CARRYING                CARRYING
                                                          AMOUNT    FAIR VALUE    AMOUNT    FAIR VALUE
                                                         --------   ----------   --------   ----------
                                                                         (IN MILLIONS)
<S>                                                      <C>        <C>          <C>        <C>
     Long-term debt and other obligations, including
       current maturities..............................   $5,354      $4,637      $6,417      $6,477
     Notes payable to unconsolidated affiliates........       --          --          67          67
     Company obligated preferred securities of
       subsidiaries....................................      300         160         300         299
     Trading price risk management activities..........      (18)        (18)        (23)        (23)
     Non-trading price risk management activities......      822         822         501         501
</Table>

     As of December 31, 2002 and 2001, our carrying amounts of cash and cash
equivalents, short-term borrowings, and trade receivables and payables are
representative of fair value because of the short-term nature of these
instruments. The fair value of long-term debt with variable interest rates
approximates its

                                        69
<PAGE>

carrying value because of the market-based nature of the debt's interest rates.
We estimated the fair value of debt with fixed interest rates based on quoted
market prices for the same or similar issues. We estimated the fair value of all
derivative financial instruments based on quoted market prices, current market
conditions, estimates we obtained from third-party brokers or dealers, or
amounts derived using valuation models.

11.  PRICE RISK MANAGEMENT ACTIVITIES

     The following table summarizes the carrying value of our trading and
non-trading price risk management assets and liabilities as of December 31:

<Table>
<Caption>
                                                              2002     2001
                                                              ----     ----
                                                              (IN MILLIONS)
<S>                                                           <C>      <C>
Net assets (liabilities)
     Trading contracts(1)...................................  $(18)    $(23)
     Non-trading contracts
       Derivatives designated as hedges.....................  (146)     501
       Other derivatives....................................   968       --
                                                              ----     ----
     Net assets from price risk management activities(2)....  $804     $478
                                                              ====     ====
</Table>

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

(1) Trading contracts are those that are entered into for purposes of generating
    a profit or benefiting from movements in market prices.

(2) Net assets from price risk management activities include current and
    non-current assets and current and non-current liabilities from price risk
    management activities on the balance sheet.

     Included in other derivatives as of December 31, 2002, are $968 million of
derivative contracts related to the power restructuring activities of our
consolidated subsidiaries. Of this amount, $878 million relates to a power
restructuring that occurred during the first quarter of 2002 at our Eagle Point
Cogeneration power plant, and $90 million relates to a power restructuring at
our Capitol District Energy Center Cogeneration Associates plant.

     Trading Activities and Contracts.  Our trading activities include the
services we provide in the energy sector that we enter into with the objective
of generating profits on or benefiting from movements in market prices,
primarily related to the purchase and sale of energy commodities.

     We have reflected our trading portfolio at estimated fair value which is
the amount at which the contracts in our portfolio could be bought or sold in a
current transaction between willing buyers and sellers. We obtained valuation
assistance from a third party valuation specialist in determining the fair value
of our trading and non-trading price risk management activities as of December
31, 2002. Based upon the specialist's input, our estimates of fair value are
based upon price curves derived from actual prices observed in the market,
pricing information supplied by the specialist and independent pricing sources
and models that rely on this forward pricing information and historical
information. These estimates may also reflect factors for time value and
volatility underlying the contracts, the potential impact of liquidating our
position in an orderly manner over a reasonable time under present market
conditions, modeling risk, credit risk of our counterparties and operational
risks, as needed.

     We serve a diverse group of customers that require a wide variety of
financial structures, products and terms. This diversity requires us to manage,
on a portfolio basis, the resulting market risks inherent in our trading price
risk management activities subject to parameters established by our risk
management committee. We monitor market risks through a risk control committee
operating independently from the units that create or actively manage these risk
exposures to ensure compliance with our stated risk management policies. We
measure and adjust the risk in accordance with mark-to-market and other risk
management methodologies which utilize forward price curves in the energy
markets to estimate the size and probability of future potential exposure.

                                        70
<PAGE>

     Credit risk relates to the risk of loss that we would incur as a result of
non-performance by counterparties pursuant to the terms of their contractual
obligations. We maintain credit policies with regard to our counterparties in
both our trading and non-trading price risk management activities to minimize
overall credit risk. These policies require an evaluation of potential
counterparties' financial condition (including credit rating), collateral
requirements under certain circumstances (including cash in advance, letters of
credit, and guarantees), and the use of standardized agreements that allow for
the netting of positive and negative exposures associated with a single
counterparty. Substantially all of our trading and non-trading price risk
management activities that are in net asset positions are with investment grade
energy marketers, financial institutions and natural gas and electric utilities
at December 31, 2002 and 2001.

     Non-trading Activities -- Derivatives Designated as Hedges.

     We use derivative financial instruments to hedge the impact of our market
price risk exposures on our assets, liabilities, contractual commitments and
forecasted transactions related to our natural gas and oil production, refining,
natural gas transmission, power generation, financing and international business
activities. We engage in two types of hedging activities: hedges of cash flow
exposure and hedges of fair value exposure. Hedges of cash flow exposure are
entered into to hedge a forecasted transaction or the variability of cash flows
to be received or paid related to a recognized asset or liability. Hedges of
fair value exposure are entered into to hedge the fair value of a recognized
asset, liability or firm commitment. On the date that we enter into the
derivative contract, we designate the derivative as either a cash flow hedge or
a fair value hedge. Changes in derivative fair values that are designated as
cash flow hedges are deferred to the extent that they are effective and are
recorded as a component of accumulated other comprehensive income until the
hedged transactions occur and are recognized in earnings. The ineffective
portion of a cash flow hedge's change in value is recognized immediately in
earnings as a component of operating revenues in our income statement. Changes
in the derivative fair values that are designated as fair value hedges are
recognized in earnings as offsets to the changes in fair values of related
hedged assets, liabilities or firm commitments.

     As required by SFAS No. 133, 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, both at the inception of the hedge and
on an on-going basis, whether the derivatives that are used in our hedging
transactions 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.

     The fair value of our hedging instruments reflects our best estimate and is
based upon exchange or over-the-counter quotations when they are available.
Quoted valuations may not be available due to location differences or terms that
extend beyond the period for which quotations are available. Where quotes are
not available, we utilize other valuation techniques or models to estimate
market values. These modeling techniques require us to make estimations of
future prices, price correlation and market volatility and liquidity. Our actual
results may differ from our estimates, and these differences can be positive or
negative.

     On January 1, 2001, we adopted the provisions of SFAS No. 133 and recorded
a cumulative-effect adjustment of $459 million, net of income taxes, in
accumulated other comprehensive income to recognize the fair value of all
derivatives designated as hedging instruments. The majority of the initial
charge related to hedging cash flows from anticipated sales of natural gas for
2001 and 2002. During the year ended December 31, 2001, $456 million, net of
income taxes, of this initial transition adjustment was reclassified to earnings
as a result of hedged sales and purchases during the year. A discussion of our
hedging activities is as follows:

     Fair Value Hedges.  We have crude oil and refined products inventories that
change in value daily due to changes in the commodity markets. We use futures
and swaps to protect the value of these inventories. For the years ended
December 31, 2002 and 2001, the financial statement impact of our hedges of the
fair value of these inventories was immaterial.

                                        71
<PAGE>

     Cash Flow Hedges.  A majority of our commodity sales and purchases are at
spot market or forward market prices. We use futures, forward contracts and
swaps to limit our exposure to fluctuations in the commodity markets and allow
for a fixed cash flow stream from these activities. As of December 31, 2002 and
2001, the value of cash flow hedges included in accumulated other comprehensive
income was a net unrealized loss of $79 million and a net unrealized gain of
$318 million, net of income taxes. We estimate that unrealized losses of $117
million, net of income taxes, will be reclassified from accumulated other
comprehensive income during 2003. Reclassifications occur upon physical delivery
of the hedge commodity and the corresponding expiration of the hedge. The
maximum term of our cash flow hedges is three years; however, most of our cash
flow hedges expire within the next 12 months.

     Our accumulated other comprehensive income as of December 31, 2002 and 2001
also includes a gain of $17 million and $1 million, net of income taxes,
representing our proportionate share of amounts recorded in other comprehensive
income by our unconsolidated affiliates who use derivatives as cash flow hedges.
Included in this gain is a $9 million gain that we estimate will be reclassified
from accumulated other comprehensive income during 2003. The maximum term of
these cash flow hedges is two years, excluding hedges related to interest rates
on variable debt.

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

     In May 2002, we announced a plan to reduce the volumes of natural gas that
we have hedged for our Production segment, and we removed the hedging
designation on derivatives that had a fair value loss of $85 million at December
31, 2002. This amount, net of income taxes of $30 million, is reflected in
accumulated other comprehensive income and will be reclassified to income as the
original hedged transactions are settled through 2004. Of the net loss of $55
million in accumulated other comprehensive income, we estimate that unrealized
losses of $29 million, net of income taxes, related to these derivatives will be
reclassified to income over the next twelve months.

     Non-trading Activities -- Power Restructuring Activities.  Our Merchant
Energy segment's power restructuring activities involve amending or terminating
a power plant's existing power purchase contract to eliminate the requirement
that the plant provide power from its own generation to the regulated utility
and replacing that requirement with the ability to provide power to the utility
from the wholesale power market. In conjunction with our power restructuring
activities, we generally entered into new market-based contracts with third
parties to provide the power to the utility from the wholesale power market,
which effectively "locks in" our margin on the restructuring transaction as the
difference between the contracted rate in the restructured contract and the
wholesale market rates at the time.

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

     Following a restructuring, the accounting treatment for the power purchase
agreement can change if the restructured contract meets the definition of a
derivative and is therefore required to be market to its fair value under SFAS
No. 133. In addition, since the power plant no longer has the exclusive right to
provide power under the original, dedicated power purchase contract, it operates
as a peaking merchant plant, generating power only when it is economical to do
so. Because of this significant change in its use, the fair value of the plant
may be less than its historical value. These changes may also require us to
terminate or amend any related fuel supply and steam agreements, and enter into
other third party and intercompany contracts such as transportation agreements,
associated with the operations of the facility.

     Our power restructuring activities have the following effects to our
financial statements:

        - The restructured contract (if it meets the definition of a derivative)
          is shown as an asset from price risk management activities in our
          balance sheet.

                                        72
<PAGE>

        - The difference between the fair value of the restructured contract and
          the carrying value of the original contract is shown as operating
          revenues in our income statement. Any subsequent changes in this fair
          value are also recorded in operating revenues.

        - The new third party wholesale power supply and other contracts are
          recorded at their fair value as liabilities from price risk management
          activities in our balance sheet. Any subsequent changes in the fair
          value are also recorded in operating revenues.

        - The carrying value of the underlying power plant and any related
          intangible assets are evaluated for impairment and, if required, are
          written down to their value as a merchant power plant, which is
          recorded as operating expenses in our income statement.

        - Any contract termination fees and closing costs are also recorded as
          operating expenses in our income statement.

        - As we purchase power under the wholesale power supply contracts, we
          record the cost of the power we purchase as operating expenses in our
          income statement.

        - As we sell that power to the utility under the restructured contract,
          we record the amounts received under the contract as operating
          revenues.

     We classify our restructured contracts as non-trading price risk management
activities in our disclosures.

     In 2002 we completed a power restructuring on our Eagle Point Cogeneration
facility, which we consolidate, and applied the accounting described above to
that transaction. We also employed the principles of our power restructuring
business in reaching a settlement in 2002 of the 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    MINORITY
                         ACTIVITIES       ACTIVITIES         ASSETS       REVENUES    EXPENSES     INTEREST
                         -----------   ----------------   -------------   ---------   ---------   ----------
<S>                      <C>           <C>                <C>             <C>         <C>         <C>
Initial gain on
  restructured
  contracts............     $978             $ 80                          $  988                   $ 172
Writedown 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>

     The fair value of the derivatives related to our power restructuring
activities is determined based on the expected cash receipts and payments under
the contracts using future power prices compared to the contractual prices under
these contracts. We discount these cash flows at an interest rate commensurate
with the term of each contract and the credit risk of each contract's
counterparty. We make adjustments to this

                                        73
<PAGE>

discount rate when we believe that market changes in the rates result in changes
in fair values that can be realized. We consider whether changes in the rates
are the result of changes in the capital markets, or are the result of sustained
economic changes. Future power prices are based on the forward pricing curve of
the appropriate power delivery and receipt points in the applicable power
market. This forward pricing curve is derived from available market data and
pricing information supplied by a third party. The timing of cash receipts and
payments are based on the expected timing of power delivered under these
contracts. The fair value of our derivatives may change each period based on
changes in actual and projected market prices, fluctuations in the credit
ratings of our counterparties, significant changes in interest rates, and
changes to the assumed timing of deliveries.

     As a result of credit downgrades and disruptions in the capital markets, it
is unlikely we will pursue additional power restructurings in the near term.

12. INVENTORY

     Our inventory consisted of the following at December 31:

<Table>
<Caption>
                                                              2002     2001
                                                              -----    -----
                                                              (IN MILLIONS)
<S>                                                           <C>      <C>
Current
  Refined products, crude oil and chemicals.................  $584     $576
  Materials and supplies and other..........................   113      107
                                                              ----     ----
          Total current inventory...........................   697      683
Non-Current
  Turbines..................................................    20       38
                                                              ----     ----
          Total.............................................  $717     $721
                                                              ====     ====
</Table>

13. PROPERTY, PLANT AND EQUIPMENT

     At December 31, 2002 and 2001, we had approximately $1,127 million and
$1,141 million of construction work in progress included in our property, plant
and equipment.

     In June 2001, we entered into a 20-year lease agreement related to our
Corpus Christi refinery and related assets with Valero. Under the lease, Valero
pays us a quarterly amount that increases after the second year of the lease.
For the years ended December 31, 2002 and 2001, we recorded $19 million and $11
million in lease income related to this lease. In February 2003, Valero
exercised its option to purchase the plant and related assets for $289 million
in cash. We recorded a gain of $8 million.

     As of December 31, 2002, ANR has excess purchase costs associated with its
acquisition. Total excess costs were approximately $2 billion and accumulated
depreciation was approximately $924 million. These excess costs are being
amortized over the life of the related pipeline assets, and our amortization
expense during 2002 was approximately $34 million. The adoption of SFAS No. 142
did not impact this amount since it was included as part of our property, plant
and equipment, rather than as goodwill.

     We have goodwill recorded as a result of the acquisitions of ANR and CIG.
This goodwill was $723 million at December 31, 2002, and $310 million of
accumulated amortization. In conjunction with adoption of SFAS 142 on January 1,
2002, we ceased our amortization of this goodwill and performed the required
impairment tests on this goodwill. No impairment of this goodwill was indicated
as of January 1, 2002 and December 31, 2002.

                                        74
<PAGE>

14. DEBT, OTHER FINANCING OBLIGATIONS AND OTHER CREDIT FACILITIES

     At December 31, 2001, our weighted average interest rate on our short-term
credit facilities was 2.4%, and there were no amounts outstanding under these
facilities at December 31, 2002. We had the following short-term borrowings and
other financing obligations at December 31:

<Table>
<Caption>
                                                              2002    2001
                                                              ----   ------
                                                              (IN MILLIONS)
<S>                                                           <C>    <C>
Current maturities of long-term debt and other financing
  obligations...............................................  $369   $1,310
Notes payable to unconsolidated affiliates..................    --       67
Short-term credit facilities................................    --       30
Other.......................................................    --        3
                                                              ----   ------
                                                              $369   $1,410
                                                              ====   ======
</Table>

  Credit Facilities

     In June 2002, El Paso amended its existing $1 billion 3-year revolving
credit and competitive advance facility to permit El Paso to issue up to $500
million in letters of credit and to adjust pricing terms. This facility matures
in August 2003. We are a designated borrower under this facility and, as such,
are jointly and severally liable for any amounts outstanding under this
facility. The interest rate varies based on El Paso's senior unsecured debt
rating, and as of December 31, 2002, an initial draw would have had a rate of
LIBOR plus 1.00% plus a 0.25% utilization fee. As of December 31, 2002, there
were no borrowings outstanding, and $456 million in letters of credit were
issued under the $1 billion facility. In February 2003, El Paso borrowed $500
million under the $1 billion facility.

  Restrictive Covenants

     We have entered into debt instruments and guaranty agreements that contain
covenants such as restrictions on debt levels, restrictions on liens securing
debt and guarantees, restrictions on mergers and on sales of assets,
capitalization requirements, dividend restrictions and cross-acceleration
provisions. A breach of any of these covenants could 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 $1.2 billion. If breached, the amounts guaranteed by the
guaranty agreements could be accelerated. The guaranty agreements also have a
$30 million cross-acceleration provision.

     In addition, we have indentures associated with our public debt that
contain $5 million cross-acceleration provisions.

  2003 Activities

     In January 2003, we retired various debt obligations of approximately $47
million. In February 2003, Valero exercised its option to purchase our Corpus
Christi refinery and we used the proceed to repay a $240 million loan that was
secured by the refinery lease with Valero.

     In March, 2003, ANR issued $300 million of 8 7/8% senior unsecured notes
due 2010, raising net proceeds of $288 million. ANR used $263 million of cash
proceeds from the offering to reduce existing intercompany payables. ANR
retained $25 million of net proceeds from the offering to fund future capital
expenditures.

                                        75
<PAGE>

     Our long-term debt and other financing obligations outstanding consisted of
the following at December 31:

<Table>
<Caption>
                                                               2002     2001
                                                              ------   ------
                                                               (IN MILLIONS)
<S>                                                           <C>      <C>
Long-term debt
  El Paso CGP
     Senior notes, 6.2% through 8.125%, due 2002 through
      2010..................................................  $1,305   $1,565
     Floating rate senior notes, due 2002 and 2003(1).......     200      600
     Senior debentures, 6.375% through 10.75%, due 2003
      through 2037..........................................   1,497    1,497
     FELINE PRIDES, 6.625% due 2004.........................      --      460
     Valero lease financing loan due 2004(2)................     240      240
  El Paso Power
     Non-recourse senior notes, 7.75% and 7.944%, due 2008
      and 2016..............................................     915       --
     Non-recourse notes 8.5%, due 2005......................     126       --
  El Paso Production Company
     Floating rate notes, due 2005 and 2006.................     200      200
  ANR Pipeline
     Debentures, 7.0% through 9.625%, due 2021 through
      2025..................................................     500      500
     Notes, 13.75% due 2010.................................      13       --
  Colorado Interstate Gas
     Debentures, 6.85% and 10.0%, due 2005 and 2037.........     280      280
  Other.....................................................      84      369
                                                              ------   ------
                                                               5,360    5,711
  Less:
     Unamortized discount...................................       6        9
     Current maturities.....................................     369      720
                                                              ------   ------
       Long-term debt, less current maturities..............   4,985    4,982
                                                              ------   ------
Other Financing Obligations
  Crude oil prepayments(3)..................................      --      500
  Natural gas production payment............................      --      215
                                                              ------   ------
                                                                  --      715
  Less:
     Current maturities.....................................      --      590
                                                              ------   ------
       Other financing obligations, less current
        maturities..........................................      --      125
                                                              ------   ------
          Total long-term debt and other financing
            obligations, less current maturities............  $4,985   $5,107
                                                              ======   ======
</Table>

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

(1) In March 2002, we retired $400 million of these notes.
(2) Collateralized by the lease payments from Valero under their lease of our
    Corpus Christi refinery. The Valero loan was repaid in February 2003.
(3) Secured by our agreement to deliver a fixed quantity of crude oil to a
    specified delivery point in the future. As of December 31, 2002, all of the
    crude oil prepayment obligations had been paid.

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

<Table>
<S>                                                           <C>
2003........................................................  $  369
2004........................................................     556
2005........................................................     364
2006........................................................     655
2007........................................................      60
Thereafter..................................................   3,356
                                                              ------
     Total long-term debt and other financing obligations
       including current maturities.........................  $5,360
                                                              ======
</Table>

                                        76
<PAGE>

     In July 2002, Utility Contract Funding issued $829 million of 7.944% senior
secured notes due in 2016. This financing is non-recourse to other El Paso
companies, as it is independently supported only by the cash flows and contracts
of Utility Contract Funding including obligations of Public Service Electric and
Gas under a restructured power contract and of Morgan Stanley under a power
supply agreement. In connection with the credit enhancement provided by Morgan
Stanley's participation, we paid them $36 million in consideration for entering
into the supply agreement.

     In August 2002, El Paso issued 12,184,444 shares of common stock to satisfy
purchase contract obligations under our FELINE PRIDES(SM) program. In return for
the issuance of the stock, we received approximately $25 million in cash from
the maturity of a zero coupon bond and the return of $435 million of our
existing 6.625% senior debentures due August 2004 that were issued in 1999. The
zero coupon bond and the senior debentures had been held as collateral for the
purchase contract obligations. The $25 million received from the maturity of the
zero coupon bond was used to retire additional senior debentures. Total debt
reduction from the issuance of the common stock was approximately $460 million.

  Other Financing Arrangements

     During 2000, El Paso formed a series of companies that it refers to as
Clydesdale. Clydesdale was formed to provide financing to invest in various
capital projects and other assets. A third-party investor contributed cash of $1
billion into Clydesdale in exchange for the preferred securities of one of El
Paso's consolidated subsidiaries. The financing arrangement is collateralized by
a combination of notes payable from us, various natural gas and oil properties,
a production payment from us and our wholly owned subsidiary Colorado Interstate
Gas Company. The credit downgrades of El Paso have resulted in the net cash
generated by these assets being largely unavailable to us for general corporate
purposes. The cash generated by these assets can only be used to redeem the
preferred securities issued in connection with these arrangements, and for the
operations of the business units associated with this transaction. As of
December 31, 2002, the total amount outstanding on the Clydedale transaction was
$950 million.

     In a series of credit rating agency actions in late 2002 and early 2003,
and contemporaneously with the downgrades of the senior unsecured indebtedness
of El Paso, our senior unsecured indebtedness was downgraded below investment
grade and is currently rated Caal by Moody's and B by Standard & Poor's and we
remain on negative credit outlook. These downgrades will increase our cost of
capital and collateral requirements and could impede our access to capital
markets in the future.

  Other Financial Activities

     Our significant long-term debt borrowing and repayment activities during
2002 were as follows:

<Table>
<Caption>
                                                                                                     NET
         DATE                 COMPANY                 TYPE            INTEREST RATE    PRINCIPAL   PROCEEDS   DUE DATE
         ----                 -------                 ----            -------------    ---------   --------   --------
                                                                                          (IN MILLIONS)
<S>                      <C>                 <C>                      <C>              <C>         <C>        <C>
Issuances
2002
  April                  Mohawk River        Senior secured notes         7.75%          $ 92        $ 90       2008
                         Funding IV(1)
  July                   Utility Contract    Senior secured notes         7.944%          829         792       2016
                         Funding(1)
Retirements
2002
  March                  El Paso CGP         Long-term debt              Variable        $400        $400       2002
  June                   El Paso CGP         Crude oil prepayment        Variable         300         300       2002
  June                   El Paso CGP         Long-term debt              Variable          90          90       2002
  Jan.-June              El Paso Oil & Gas   Natural gas production      Variable         215         215     2002-2005
                         Resources             payment
  July                   El Paso CGP         Long-term debt              Variable          55          55       2002
  August                 El Paso CGP(2)      Long-term debt               6.20%            10           9       2004
  August                 El Paso CGP         Long-term debt               6.625%          460          25(3)    2004
  June-Aug.              El Paso CGP         Long-term debt              Variable          51          51     2010-2028
  September              El Paso CGP         Long-term debt               8.125%          250         250       2002
  Jan.-Sept.             El Paso CGP         Long-term debt              Variable         106         106       2002
</Table>

                                        77
<PAGE>

<Table>
<Caption>
                                                                                                     NET
         DATE                 COMPANY                 TYPE            INTEREST RATE    PRINCIPAL   PROCEEDS   DUE DATE
         ----                 -------                 ----            -------------    ---------   --------   --------
                                                                                          (IN MILLIONS)
<S>                      <C>                 <C>                      <C>              <C>         <C>        <C>
  Jan.-Sept.             Various             Long-term debt              Various           30          30       2002
  November               El Paso CGP         Long-term debt              Variable          60          60       2002
  Oct.-Dec.              El Paso CGP         Crude Oil prepayment        Various          200         200       2002
</Table>

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

(1) These notes are collateralized solely by the cash flows and contracts of
    these consolidated subsidiaries, and are non-recourse to our parent and
    other affiliated companies. The Mohawk River Funding IV financing relates to
    our Capitol District Energy Center Cogeneration Associates restructuring
    transaction, and the Utility Contract Funding financing relates to our Eagle
    Point Cogeneration restructuring transaction.

(2) These amounts represent a buyback of our bonds in the open market in July
    and August 2002.

(3) The majority of this debt was exchanged for El Paso common stock.

15. 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,
2002 and 2001, were as follows (in millions):

<Table>
<Caption>
                                                              2002   2001
                                                              ----   ----
<S>                                                           <C>    <C>
Coastal Finance I consolidated trust........................  $300   $300
Preferred stock of subsidiaries.............................   100    165
Consolidated partnership....................................    --    285
                                                              ----   ----
                                                              $400   $750
                                                              ====   ====
</Table>

     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
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, or earlier if various events occur. 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.

     Coastal Securities Company 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. Quarterly cash dividends are being paid on
the preferred stock at a rate based on LIBOR plus a margin of 2.11% based on our
long-term unsecured debt rating. The holders of the preferred securities have a
right to reset the dividend rate on December 20, 2003 and every seven years
thereafter. If the new rate is not acceptable to the preferred holders, they
have a right to require us to redeem the preferred securities. The preferred
holders are also entitled to participating dividends based on refining margins
of our Aruba refinery. Coastal Securities may redeem the preferred stock for
cash at the liquidation price of $100 million plus accrued and unpaid dividends.

     El Paso Oil & Gas Resources Preferred Units.  In 1999, El Paso Oil & Gas
Resources Company, L.P. (formerly Coastal Oil & Gas Resources, Inc.), our wholly
owned subsidiary, issued 50,000 units of preferred units for $50 million to
UAGC, Inc., a subsidiary of Rabobank International. The preferred shareholders
were entitled to quarterly cash dividends at a rate based on LIBOR. In July
2002, we repurchased the entire 50,000 units for $50 million plus accrued and
unpaid dividends.

                                        78
<PAGE>

     Coastal Limited Ventures Preferred Stock.  In 1999, Coastal Limited
Ventures, Inc., our wholly owned subsidiary, issued 150,000 shares of preferred
stock for $15 million to JP Morgan Chase Bank (formerly Chase Manhattan Bank).
The preferred shareholders were entitled to quarterly cash dividends at an
annual rate of 6%. In July 2002, we repurchased the entire 150,000 shares for
$15 million plus accrued and unpaid dividends.

     Consolidated Partnership. In December 1999, Coastal Limited Ventures
contributed assets to a limited partnership in exchange for a controlling
general partnership interest. Limited interests in the partnership were issued
to RBCC, an unaffiliated investor for $285 million. The limited partners were
entitled to a cumulative priority return based on LIBOR. In July 2002, we
repurchased the limited partnership interest in El Paso Production Oil & Gas
Associates, L.P., formerly known as Coastal Oil and Gas Associates and a
partnership formed with Coastal Limited Ventures, Inc. The payment of
approximately $285 million to the unaffiliated investor was equal to the sum of
the limited partner's outstanding capital plus unpaid priority returns.

     Coastal Finance I and Coastal Securities Company Limited are either
business trusts we control or companies in which we own all of the voting stock.
Consequently, they are consolidated in our financial statements. However, these
entities have issued preferred securities, and these preferred interests that
are held by various unaffiliated investors are presented in our balance sheet as
preferred interests of consolidated subsidiaries. The preferred distributions
paid on these preferred interests are presented in our income statement as
return on preferred interests of consolidated subsidiaries. Our accounting for
some of these preferred interests of consolidated subsidiaries will be impacted
by our adoption of the new accounting rules on consolidations in July 2003. For
a discussion of the accounting impact, see Note 1 under New Accounting
Pronouncements Issued But Not Yet Adopted.

16. COMMITMENTS AND CONTINGENCIES

  Legal Proceedings

     Grynberg.  In 1997, a number of our subsidiaries were named defendants in
actions 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 of
natural gas produced from royalty properties 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). In May 2001, the court denied the
defendants' motions to dismiss. 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 were named
defendants in Quinque Operating Company, et al v. Gas Pipelines and Their
Predecessors, et al, filed in 1999 in the District Court of Stevens County,
Kansas. Quinque has been dropped as a plaintiff and Will Price has been added.
This class action complaint alleges that the defendants mismeasured natural gas
volumes and heating content of natural gas on non-federal and non-Native
American lands. The plaintiff in this case seeks certification of a nationwide
class of natural gas working interest owners and natural gas royalty owners to
recover royalties that the plaintiff contends these owners 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,
attorney's 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 has been argued and we are awaiting a ruling. Our costs and legal
exposure related to this lawsuit are not currently determinable.

                                        79
<PAGE>

     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 also produce, buy, sell and distribute MTBE. A number of lawsuits
have been filed throughout the U.S. regarding MTBE's potential impact on water
supplies. We are currently one of several defendants in one such lawsuit in New
York. The plaintiffs seek remediation of their groundwater and prevention of
future contamination, compensatory damages for the costs of replacement water
and for diminished property values, as well as punitive damages, attorney's
fees, court costs, and, in some cases, future medical monitoring. Our costs and
legal exposure related to this lawsuit and claims are not currently
determinable.

     Cimarron County.  In January of 2003, one of our subsidiaries, CIG Field
Services Company (CIG), was named a defendant in a suit titled Patty Hiner, As
Duly Elected County Assessor, The Board of County Commissioners for Cimarron
County, Oklahoma v. CIG in Cimarron County District Court, alleging that in 1999
its agents falsely represented the value of its property to the Cimarron County
Property Tax Assessor. The plaintiffs seek compensatory and punitive damages.
CIG is in the process of moving the case to the United States District Court for
the Western District of Oklahoma for trial. Our costs and legal exposure related
to this lawsuit and claims are not currently determinable.

     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 of December 31, 2002, we had approximately $55 million accrued for all
outstanding legal matters.

  Environmental Matters

     We are subject to extensive 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, 2002, we had accrued approximately $156 million,
including approximately $155 million for expected remediation costs at current
and former operated sites and associated onsite, offsite and groundwater
technical studies, and approximately $1 million for related environmental legal
costs, which we anticipate incurring through 2027. Approximately $15 million of
the accrual was related to discontinued coal mining operations. The high end of
our reserve estimates was approximately $224 million and the low end was
approximately $134 million, and our accrual at December 31, 2002 was based on
the estimated most likely reasonable amount of liability. By type of site, our
reserves are based on the following estimates of reasonably possible outcomes.

<Table>
<Caption>
                                                                   DECEMBER 31,
                                                                       2002
                                                                  --------------
    SITES                                                          LOW     HIGH
    -----                                                         -----    -----
                                                                  (IN MILLIONS)
    <S>                                                           <C>      <C>
    Operating...................................................  $103     $158
    Non-operating...............................................    31       65
    Superfund...................................................    --        1
</Table>

                                        80
<PAGE>

     Below is a reconciliation of our accrued liability as of December 31, 2001
to our accrued liability as of December 31, 2002:

<Table>
<Caption>
                                                                  2002     2001
                                                                  -----    -----
                                                                  (IN MILLIONS)
    <S>                                                           <C>      <C>
    Balance as of January 1.....................................  $260     $ 28
    Additions/adjustments for remediation activities............    14      242
    Payments for remediation activities.........................   (23)     (10)
    Other changes, net..........................................   (95)      --
                                                                  ----     ----
    Balance as of December 31...................................  $156     $260
                                                                  ====     ====
</Table>

     In addition, we expect to make capital expenditures for environmental
matters of approximately $199 million in the aggregate for the years 2003
through 2007. These expenditures primarily relate to compliance with clean air
regulations. For 2003, we estimate that our total remediation expenditures will
be approximately $23 million. In addition, approximately $16 million of this
amount will be expended under government directed clean-up plans. The remaining
$7 million will be self-directed or in connection with facility closures.

     Coastal Eagle Point.  From May 1999 to March 2001, our 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). All of the assessments are related to alleged
noncompliance with the New Jersey Air Pollution Control Act pertaining to excess
emissions from the first quarter 1998 through the fourth quarter 2000 reported
by our Eagle Point refinery in Westville, New Jersey. The DEP has assessed
penalties totaling approximately $1.3 million for these alleged violations. The
DEP has indicated a willingness to accept a reduced penalty and a supplemental
environmental project. Our Eagle Point refinery has been granted an
administrative hearing on issues raised by the assessments. Under its global
refinery enforcement initiative, the Environmental Protection Agency (EPA)
referred several Clean Air Act issues to the DEP. Our Eagle Point refinery
expects to resolve these issues along with the DEP assessments. On February 24,
2003, EPA Region 2 issued a Compliance Order based on a 1999 EPA inspection of
the refinery's leak detection and repair program. Alleged violations include
failure to monitor all components, and failure to timely repair leaking
components. During an August 2000 follow-up inspection, the EPA confirmed our
Eagle Point refinery had improved implementation of the program. The Compliance
Order requires documentation of compliance with the program. Our Eagle Point
refinery has requested a conference with the EPA to discuss the Order and the
alleged violations. The EPA may seek a monetary penalty.

     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 27 active sites under the
Comprehensive Environmental Response, Compensation and Liability Act (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, 2002, 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 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.

     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

                                        81
<PAGE>

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.

  Rates and Regulatory Matters

     Rate Case.  In March 2001, CIG filed a rate case with the Federal Energy
Regulatory Commission (FERC) proposing increased rates of $9 million annually
and new and enhanced services for its customers. In April 2001, CIG received an
order from the FERC, which suspended the rates subject to refund, and subject to
the outcome of hearing. On September 26, 2001, the FERC approved certain of its
new or enhanced services but rejected two firm services proposed in CIG's rate
filing and required it to reallocate the costs allocated to those two services
to existing services. CIG complied with this order and arranged with the
affected customers to provide service under existing rate schedules. CIG and its
customers entered into a settlement agreement in May 2002 settling all issues in
the case. The settlement, which contained a small rate increase, was approved by
the FERC, and became final in September 2002. The settlement obligates CIG to
file a new rate case to be effective no later than October 1, 2006. CIG paid
approximately $8 million, including interest, in customer refunds in November
2002. These refunds were included in accrued liabilities, and will not have an
adverse effect on our financial position or results of operations. On March 13,
2003, the FERC issued an order approving CIG's refund report.

     Marketing Affiliate NOPR.  In September 2001, the FERC issued a Notice of
Proposed Rulemaking (NOPR). The NOPR proposes to apply the standards of conduct
governing the relationship between interstate pipelines and marketing affiliates
to all energy affiliates. The proposed regulations, if adopted by the FERC,
would dictate how all our energy affiliates conduct business and interact with
our interstate pipelines. In December 2001, we filed comments with the FERC
addressing our concerns with the proposed rules. A public hearing was held on
May 21, 2002, providing an opportunity to comment further on the NOPR. Following
the conference, additional comments were filed by our pipeline subsidiaries and
others. At this time, we cannot predict the outcome of the NOPR, but adoption of
the regulations in their proposed form would, at a minimum, place additional
administrative and operational burdens on us.

     Negotiated Rate NOI.  In July 2002, the FERC issued a Notice of Inquiry
(NOI) that seeks comments regarding its 1996 policy of permitting pipelines to
enter into negotiated rate transactions. Our pipelines have entered into these
transactions over the years, and the FERC is now reviewing whether negotiated
rates should be capped, whether or not the "recourse rate" (a cost-of-service
based rate) continues to safeguard against a pipeline exercising market power
and other issues related to negotiated rate programs. On
September 25, 2002, our pipelines and others filed comments. Reply comments were
filed on October 25, 2002. At this time, we cannot predict the outcome of this
NOI.

     Cash Management NOPR.  On August 1, 2002, the FERC issued a NOPR requiring
that all cash management or money pool arrangements between a FERC regulated
subsidiary and a non-FERC regulated parent must be in writing, and set forth the
duties and responsibilities of cash management participants and administrators;
the methods of calculating interest and for allocating interest income and
expenses; and the restrictions on deposits or borrowings by money pool members.
The NOPR also requires specified documentation for all deposits into, borrowings
from, interest income from, and interest expenses related to, these
arrangements. Finally, the NOPR proposed that as a condition of participating in
a cash management or money pool arrangement, the FERC regulated entity maintain
a minimum proprietary capital balance of 30 percent, and the FERC regulated
entity and its parent maintain investment grade credit ratings. On August 28,
2002, comments were filed. The FERC held a public conference on September 25,
2002, to discuss the issues raised in the comments. Representatives of companies
from the gas and electric industries participated on a panel and uniformly
agreed that the proposed regulations should be revised substantially and that
the proposed capital balance and investment grade credit rating requirements
would be excessive. At this time, we cannot predict the outcome of this NOPR.

     Also on August 1, 2002, the FERC's Chief Accountant issued an Accounting
Release, to be effective immediately. The Accounting Release provides guidance
on how companies should account for money pool arrangements and the types of
documentation that should be maintained for these arrangements. However, it

                                        82
<PAGE>

did not address the proposed requirements that the FERC regulated entity
maintain a minimum proprietary capital balance of 30 percent and that the entity
and its parent have investment grade credit ratings. Requests for rehearing were
filed on August 30, 2002. The FERC has not yet acted on the rehearing requests.

     Emergency Reconstruction of Interstate Natural Gas Facilities NOPR.  On
January 17, 2003, FERC issued a NOPR proposing to (1) expand the scope of
construction activities authorized under a pipeline's blanket certificate to
allow replacement of mainline facilities; (2) authorize a pipeline to commence
reconstruction of the affected system without a waiting period; and (3)
authorize automatic approval of construction that would be above the normal cost
ceiling. Comments on the NOPR were filed on February 27, 2003. At this time, we
cannot predict the outcome of this rulemaking.

     Pipeline Safety Notice of Proposed Rulemaking.  On January 28, 2003, the
U.S. Department of Transportation issued a NOPR proposing to establish a rule
requiring pipeline operators to develop integrity management programs to
comprehensively evaluate their pipelines, and take measures to protect pipeline
segments located in what the notice refers to as "high consequence areas." The
proposed rule resulted from the enactment of the Pipeline Safety Improvement Act
of 2002, a new bill signed into law in December 2002. We intend to submit
comments on the NOPR, which are due on or before April 30, 2003. At this time,
we cannot predict the outcome of this rulemaking.

     FERC Inquiry.  On February 26, 2003, El Paso received a letter from the
Office of the Chief Accountant at the FERC requesting details of its
announcement of 2003 asset sales and plans for us and our pipeline affiliates to
issue a combined $700 million of long-term notes. The letter requested that El
Paso explain how it intended to use the proceeds from the issuance of the notes
and if the notes will be included in the two regulated companies' capital
structure for rate-setting purposes. Our response to the FERC was filed on March
12, 2003, and we fully responded to the request.

     While the outcome of our outstanding legal matters, environmental matters,
and rates and regulatory matters cannot be predicted with certainty, based on
current information and our existing accruals, we do not expect the ultimate
resolution of these matters to have a material adverse effect on our financial
position, operating results or cash flows. However, it is possible that new
information or future developments could require us to reassess our potential
exposure related to these matters. It is also possible that these matters could
impact our debt rating and credit rating. Further, for environmental matters, 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
new information regarding our outstanding legal matters, environmental matters
and rates and regulatory matters becomes available, or relevant developments
occur, we will review our accruals and make any appropriate adjustments. The
impact of these changes may have a material effect on our results of operations,
our financial position, and on our cash flows in the period the event occurs.

  Capital Commitments and Purchase Obligations

     At December 31, 2002, we had capital and investment commitments of $98
million primarily relating to our Production, Pipeline and Merchant Energy
activities, which include obligations for natural gas purchases, transportation
and storage capacity, maintenance and capital investments. Our other planned
capital and investment projects are discretionary in nature, with no substantial
capital commitments made in advance of the actual expenditures. Our pipelines
have entered into unconditional purchase obligations for products and services
totaling $235 million at December 31, 2002. Our annual obligations under these
agreements are $23 million for each of the years 2003 through 2007, and $120
million in total thereafter.

  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
2002 until 2031. As of December 31, 2002, our total commitments under operating
leases were approximately $397 million.

                                        83
<PAGE>

     Under one of our leases, we have provided a residual value guarantee to the
lessor. For the total outstanding residual value guarantee on our Aruba
operating lease at December 31, 2002, see Residual Value Guarantees below.

     Minimum annual rental commitments at December 31, 2002, were as follows:(1)

<Table>
<Caption>
                        YEAR ENDING
                        DECEMBER 31,                          OPERATING LEASES
------------------------------------------------------------  ----------------
                                                              (IN MILLIONS)
<S>                                                           <C>
   2003.....................................................        $103
   2004.....................................................          78
   2005.....................................................          46
   2006.....................................................          33
   2007.....................................................          23
   Thereafter...............................................         114
                                                                    ----
          Total.............................................        $397
                                                                    ====
</Table>

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

(1) These amounts exclude minimum annual rental commitments paid by our parent,
    which are allocated to us through an overhead allocation.

     Rental expense for the years ended December 31, 2002, 2001 and 2000 was
$136 million, $92 million and $140 million.

  Letters of Credit

     We enter into letters of credit in the ordinary course of our operating
activities. As of December 31, 2002, we had no outstanding letters of credit
related to the marketing and trading activities, and $51 million related to the
domestic power development and other operating activities.

  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, 2002, we had approximately $50 million of guarantees in
connection with our international development and operating activities not
consolidated on our balance sheet and approximately $11 million of guarantees in
connection with our domestic development and operating activities not
consolidated on our balance sheet.

  Residual Value Guarantees

     Under one of our operating leases, we have provided a residual value
guarantee to the lessor. Under this guarantee, we can either choose to purchase
the asset at the end of the lease term for a specified amount, which is equal to
the outstanding loan amount owed by the lessor, or we can choose to assist in
the sale of the leased asset to a third party. Should the asset not be sold for
a price that equals or exceeds the amount of the guarantee, we would be
obligated for the shortfall. The level of our residual value guarantee is 89.9
percent of the original cost of the leased assets. Accounting for this residual
value guarantee will be impacted effective July 1, 2003 by our adoption of the
new accounting rules on consolidations. For a discussion of the accounting
impact of these new rules, see Note 1.

                                        84
<PAGE>

     As of December 31, 2002, we had purchase options and residual value
guarantees associated with operating lease for the following asset:

<Table>
<Caption>
                                                      PURCHASE   RESIDUAL VALUE     LEASE
ASSET DESCRIPTION                                      OPTION      GUARANTEE      EXPIRATION
-----------------                                     --------   --------------   ----------
                                                                  (IN MILLIONS)
<S>                                                   <C>        <C>              <C>
Facility at Aruba refinery..........................    $370          $333           2006
</Table>

17. RETIREMENT BENEFITS

  Pension and Retirement Benefits

     El Paso maintains a pension plan to provide benefits as determined by a
cash balance formula covering substantially all of its U.S. employees, including
our employees except for employees of our coal and retail operations who are
covered under separate plans. El Paso also maintains a defined contribution plan
covering its U.S. employees, including our employees. 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. El Paso is responsible for benefits accrued
under its plan and allocates the related costs to its affiliates.

     Prior to our merger with El Paso, we maintained both defined benefit and
defined contribution 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. Effective September 30, 2002,
the Coastal Mart pension plan was frozen. Effective March 17, 2003, the Coastal
Coal pension plan was frozen. In addition, we maintained a defined contribution
plan. Under this plan, we matched 100 percent of basic contributions of up to 8
percent with matching contributions made in our common stock. On January 29,
2001, this plan was merged into El Paso defined Contribution plan.

  Other Postretirement Benefits

     As a result of our merger with El Paso, El Paso offered a one-time election
through an early retirement window for employees who were at least age 50 with
10 years of service on December 31, 2000, to retire on or before June 30, 2001,
and keep benefits under our postretirement medical and life plans. Total charges
associated with the curtailment and special termination benefits were $65
million. Medical benefits for this closed group of retirees may be subject to
deductibles, co-payment provisions and other limitations and dollar caps on the
amount of employer costs. El Paso has reserved the right to change these
benefits. Employees who retire on or after June 30, 2001, will continue to
receive limited postretirement life insurance benefits. Our postretirement
benefit plan costs are pre-funded to the extent such costs are recoverable
through rates.

     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.

                                        85
<PAGE>

     Due to a Corporate-wide restructuring during 2002, Coastal Mart is no
longer part of us. As a result, the 2002 pension benefits shown below only
reflect our Coal benefits, while the year-end 2001 pension benefits reflect both
our Coastal Mart and our Coal pension benefits. The following table sets forth
the change in benefit obligation, change in plan assets, reconciliation of
funded status and components of net periodic benefit cost for pension benefits
and other postretirement benefits for the twelve months ended September 30.

<Table>
<Caption>
                                                                           POSTRETIREMENT
                                                       PENSION BENEFITS       BENEFITS
                                                       ----------------    ---------------
                                                       2002      2001       2002    2001
                                                       -----   --------    ------  -------
                                                                  (IN MILLIONS)
<S>                                                    <C>     <C>         <C>      <C>
Change in benefit obligation
  Benefit obligation at beginning of period..........  $ 84    $   822      $109     $114
  Service cost.......................................     3          5         1        1
  Interest cost......................................     5         20         8        9
  Participant contributions..........................    --         --         4        3
  Plan amendment.....................................    --         --        --      (12)
  Curtailment and special termination benefit........    --        137        --       16
  Actuarial loss (gain)..............................    10         75        (5)     (15)
  Benefits paid......................................    (3)       (13)      (15)      (7)
  Transfer of plan obligations.......................   (20)      (962)       --       --
                                                       ----    -------      ----     ----
  Benefit obligation at end of period................  $ 79    $    84      $102     $109
                                                       ====    =======      ====     ====
Change in plan assets
  Fair value of plan assets at beginning of period...  $ 97    $ 1,971      $ 40     $ 35
  Actual return on plan assets.......................    (8)      (182)       (1)       1
  Employer contributions.............................    --         --        18        8
  Participant contributions..........................    --         --         4        3
  Benefits paid......................................    (3)       (13)      (15)      (7)
  Transfer of plan assets............................   (27)    (1,679)       --       --
                                                       ----    -------      ----     ----
  Fair value of plan assets at end of period.........  $ 59    $    97        46     $ 40
                                                       ====    =======      ====     ====
Reconciliation of funded status
  Funded status at end of period.....................  $(20)   $    13      $(56)    $(69)
  Fourth quarter contributions.......................    --         --         4        4
  Unrecognized net actuarial loss (gain).............    28         14       (29)     (29)
  Unrecognized prior services costs..................     1         --        --       --
  Other..............................................    --          1        --       --
                                                       ----    -------      ----     ----
  Prepaid (accrued) benefit cost at December 31, ....  $  9    $    28      $(81)    $(94)
                                                       ====    =======      ====     ====
Amounts recognized in the statement of financial
  position consist of:
  Prepaid benefit cost...............................  $ --    $    28
  Accrued benefit liability..........................   (11)        --
  Intangible asset...................................     1         --
  Accumulated other comprehensive income.............    19         --
                                                       ----    -------
  Net amount recognized at year-end..................  $  9    $    28
                                                       ====    =======
  Other comprehensive income attributable to change
     in additional minimum liability recognition.....  $ 19    $    --
                                                       ====    =======
</Table>

                                        86
<PAGE>

     Included in the above information is the projected benefit obligation,
accumulated benefit obligation, and fair value of plan assets for the pension
plan with accumulated benefit obligations in excess of plan assets of $79
million, $70 million, and $59 million as of December 31, 2002.

<Table>
<Caption>
                                                     PENSION           POSTRETIREMENT
                                                    BENEFITS              BENEFITS
                                               -------------------   ------------------
                                                       YEAR ENDED DECEMBER 31,
                                               ----------------------------------------
                                               2002   2001   2000    2002   2001   2000
                                               ----   ----   -----   ----   ----   ----
                                                            (IN MILLIONS)
<S>                                            <C>    <C>    <C>     <C>    <C>    <C>
Benefit cost for the plans includes the
  following components
  Service cost..............................   $ 3    $  5   $  21   $ 1    $ 1    $ 3
  Interest cost.............................     5      20      59     8      9      8
  Expected return on plan assets............    (7)    (55)   (164)   (2)    (2)    (1)
  Amortization of net actuarial gain........    --      (9)    (20)   (1)    --     (2)
  Amortization of transition obligation.....    --      (2)     (8)   --     --      6
  Amortization of prior service cost........    --      --       1    --     --      1
  Curtailment and special termination
     benefit................................    --     137      --    --     65     --
                                               ---    ----   -----   ---    ---    ---
  Net benefit cost (income).................   $ 1    $ 96   $(111)  $ 6    $73    $15
                                               ===    ====   =====   ===    ===    ===
</Table>

     Benefit obligations are based upon actuarial estimates as described below:

<Table>
<Caption>
                                                                            POSTRETIREMENT
                                                        PENSION BENEFITS       BENEFITS
                                                        ----------------    --------------
                                                         2002      2001     2002     2001
                                                        ------    ------    -----    -----
<S>                                                     <C>       <C>       <C>      <C>
Weighted average assumptions
  Discount rate.......................................   6.75%     7.25%    6.75%    7.25%
  Expected return on plan assets......................   8.80%    10.00%    7.50%    7.50%
  Rate of compensation increase.......................   4.00%     4.00%      --       --
</Table>

     Actuarial estimates for our postretirement benefits plans assumed a
weighted average annual rate of increase in the per capita costs for covered
health care benefits of 11.0 percent in 2002, 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 from assumed health care cost trends would have the
following effects:

<Table>
<Caption>
                                                              2002    2001
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
One Percentage Point Increase
  Aggregate of service cost and interest cost...............  $ --    $ --
  Accumulated postretirement benefit obligation.............  $  2    $  3
One Percentage Point Decrease
  Aggregate of service cost and interest cost...............  $ --    $ --
  Accumulated postretirement benefit obligation.............  $ (2)   $ (3)
</Table>

                                        87
<PAGE>

18. SEGMENT INFORMATION

     We segregate our business activities into four distinct 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. In the second quarter of 2002, we reclassified our
historical coal mining operations from our Merchant Energy segment to
discontinued operations in our financial statements. All periods were restated
to reflect this change.

     Our Pipelines segment provides natural gas transmission, storage, gathering
and related services in the U.S. and internationally. We conduct our activities
primarily through three wholly owned and two partially owned interstate
transmission systems along with five underground natural gas storage entities.
Our pipeline operations also include access between our U.S. based systems and
Canada.

     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 wellhead-to-mainline
services, including natural gas gathering, products extraction, fractionation,
dehydration, purification, compression and transportation of natural gas and
natural gas liquids. Field Services' assets are located in the south Texas,
south Louisiana, Mid-Continent and Rocky Mountain regions.

     Our Merchant Energy segment consists of two primary divisions: global power
and petroleum. We buy, sell and trade natural gas, power, crude oil, refined
products, coal and other energy commodities throughout the world, and own or
have interests in 19 power plants in 8 countries.

                                        88
<PAGE>

     We use EBIT to assess the operating results and effectiveness of our
business segments. We define EBIT as operating income, adjusted for several
items, including: earnings from unconsolidated affiliates, minority interests on
consolidated, but less than wholly-owned operating subsidiaries and other
miscellaneous non-operating items. Items that are not included in this measure
are financing costs, including interest and debt expense and returns on
preferred interests of consolidated subsidiaries, income taxes, discontinued
operations, extraordinary items and the impact of accounting changes. We believe
this measurement is useful to our investors because it allows them to evaluate
the effectiveness of our businesses and operations and our investments from an
operational perspective, exclusive of the costs to finance those activities and
exclusive of income taxes, neither of which are directly relevant to the
efficiency of those operations. This measurement may not be comparable to
measurements used by other companies and should not be used as a substitute for
net income or other performance measures such as operating cash flow. The
following are our segment results as of and for the years ended December 31:

<Table>
<Caption>
                                                                   SEGMENTS
                                                AS OF OR FOR THE YEAR ENDED DECEMBER 31, 2002
                                      ------------------------------------------------------------------
                                                                FIELD      MERCHANT
                                      PIPELINES   PRODUCTION   SERVICES     ENERGY    OTHER(1)    TOTAL
                                      ---------   ----------   --------    --------   --------   -------
                                                                (IN MILLIONS)
<S>                                   <C>         <C>          <C>         <C>        <C>        <C>
Revenues from external customers
  Domestic..........................   $  893       $1,092      $ 404       $5,054(2)  $  --     $ 7,443
  Foreign...........................        3           71          3        1,010(2)     --       1,087
Intersegment revenue................       30           95         53         (147)(2)    (31)        --
Restructuring costs.................       --           --         --            5        --           5
(Gain) loss on long-lived assets....      (12)         708        (21)         114         2         791
Ceiling test charges................       --          245         --           --        --         245
Depreciation, depletion and
  amortization......................      116          446         14           92        13         681
Operating income (loss).............   $  419       $ (461)     $  67       $  150     $ (39)    $   136
Earnings (loss) from unconsolidated
  affiliates........................      105            4        (54)          49        --         104
Minority interests in consolidated
  subsidiaries......................       --           --         --          (52)       --         (52)
Other income........................       16            1          1           72        28         118
Other expense.......................       (3)          --         (1)         (26)       (7)        (37)
                                       ------       ------      -----       ------     -----     -------
EBIT................................   $  537       $ (456)     $  13       $  193     $ (18)    $   269
                                       ======       ======      =====       ======     =====     =======
Discontinued operations, net of
  income taxes......................   $   --       $   --      $  --       $   --     $(124)    $  (124)
Cumulative effect of accounting
  changes, net of income taxes......       --           --         --           14        --          14
Assets
  Domestic..........................    5,116        3,750        403        4,339       585(3)   14,193
  Foreign...........................       59          620         14        2,146       201       3,040
Capital expenditures and investments
  in unconsolidated affiliates......      252        1,124         20          281        98       1,775
Total investments in unconsolidated
  affiliates........................      404          114         97          912        17       1,544
</Table>

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

(1) Includes our Corporate and eliminations of intercompany transactions, our
    retail business. Our intersegment revenues, along with our intersegment
    operating expenses, consist of normal course of business-type transactions
    between our operating segments. We record an intersegment revenue
    elimination, which is the only elimination included in the "Other" column,
    to remove intersegment transactions.

(2) Merchant Energy revenues take into account the adoption of a consensus
    reached on EITF Issue No. 02-3, which requires us to report all physical
    sales of energy commodities in our energy trading activities on a net basis
    as a component of revenues. See Note 1 regarding the adoption of this Issue.

(3) Includes $106 million of assets that are classified as discontinued
    operations.

                                        89
<PAGE>

<Table>
<Caption>
                                                                    SEGMENTS
                                                  AS OF OR FOR THE YEAR ENDED DECEMBER 31, 2001
                                       -------------------------------------------------------------------
                                                                 FIELD     MERCHANT
                                       PIPELINES   PRODUCTION   SERVICES    ENERGY     OTHER(1)     TOTAL
                                       ---------   ----------   --------   --------    --------    -------
                                                                  (IN MILLIONS)
<S>                                    <C>         <C>          <C>        <C>         <C>         <C>
Revenues from external customers
  Domestic...........................   $  982       $1,772       $822      $4,077(2)   $  355     $ 8,008
  Foreign............................        2           46          4         664(2)       --         716
Intersegment revenue.................       70          (35)        68         199(2)     (302)         --
Merger-related costs.................      192           45         13          44         520         814
Loss on long-lived assets............       22           16         --         127          10         175
Ceiling test charges.................       --          115         --          --          --         115
Depreciation, depletion and
  amortization.......................      137          453         15          72          21         698
Operating income (loss)..............   $  195       $  785       $ 55      $ (263)     $ (714)    $    58
Earnings from unconsolidated
  affiliates.........................       98            4         16         115          --         233
Other income.........................        8            3         --         159          20         190
Other expense........................       (9)          (1)        --         (14)         (4)        (28)
                                        ------       ------       ----      ------      ------     -------
EBIT.................................   $  292       $  791       $ 71      $   (3)     $ (698)    $   453
                                        ======       ======       ====      ======      ======     =======
Discontinued operations, net of
  income taxes.......................   $   --       $   --       $ --      $   --      $   (5)    $    (5)
Extraordinary items, net of income
  taxes..............................       --           --         (4)         (7)         --         (11)
Assets
  Domestic...........................    5,347        5,761        529       2,493         669(3)   14,799
  Foreign............................       14          773         17       3,431          32       4,267
Capital expenditures and investments
  in unconsolidated affiliates.......      421        1,814         53         142         136       2,566
Total investments in unconsolidated
  affiliates.........................      547          110        168       1,041          16       1,882
</Table>

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

(1) Includes our Corporate and eliminations of intercompany transactions, our
    retail business. Our intersegment revenues, along with our intersegment
    operating expenses, consist of normal course of business-type transactions
    between our operating segments. We record an intersegment revenue
    elimination, which is the only elimination included in the "Other" column,
    to remove intersegment transactions.

(2) Merchant Energy revenues take into account the adoption of a consensus
    reached on EITF Issue No. 02-3, which requires us to report all physical
    sales of energy commodities in our energy trading activities on a net basis
    as a component of revenues. See Note 1 regarding the adoption of this Issue.

(3) Includes $352 million of assets that are classified as discontinued
    operations.

                                        90
<PAGE>

<Table>
<Caption>
                                                                    SEGMENTS
                                                  AS OF OR FOR THE YEAR ENDED DECEMBER 31, 2000
                                       -------------------------------------------------------------------
                                                                 FIELD     MERCHANT
                                       PIPELINES   PRODUCTION   SERVICES    ENERGY     OTHER(1)     TOTAL
                                       ---------   ----------   --------   --------    --------    -------
                                                                  (IN MILLIONS)
<S>                                    <C>         <C>          <C>        <C>         <C>         <C>
Revenues from external customers
  Domestic...........................   $  972       $  806       $709      $9,957(2)   $1,191     $13,635
  Foreign............................       --            5          2       1,974(2)       --       1,981
Intersegment revenue.................       73          320         44         336(2)     (773)         --
Merger-related costs.................       --           --         --          --          13          13
(Gain) loss on long-lived assets.....        1           --         (3)         (4)          1          (5)
Depreciation, depletion and
  amortization.......................      132          399          8          73          30         642
Operating income.....................   $  387       $  417       $ 89      $  137      $   43     $ 1,073
Earnings from unconsolidated
  affiliates.........................       97           --         23         160           1         281
Other income.........................       16            1         --          74          35         126
Other expense........................       --           (5)        (1)         (3)         (1)        (10)
                                        ------       ------       ----      ------      ------     -------
EBIT.................................   $  500       $  413       $111      $  368      $   78     $ 1,470
                                        ======       ======       ====      ======      ======     =======
Discontinued operations, net of
  income taxes.......................   $   --       $   --       $ --      $   (1)     $   --     $    (1)
Assets
  Domestic...........................    5,182        4,038        512       4,922       1,780(3)   16,434
  Foreign............................       83          198         17       2,086          57       2,441
Capital expenditures and investments
  in unconsolidated affiliates.......      232        1,583         45         446          23       2,329
Total investments in unconsolidated
  affiliates.........................      609           --        193         794          17       1,613
</Table>

---------------
(1) Includes our Corporate and eliminations of intercompany transactions, our
    retail business. Our intersegment revenues, along with our intersegment
    operating expenses, consist of normal course of business-type transactions
    between our operating segments. We record an intersegment revenue
    elimination, which is the only elimination included in the "Other" column,
    to remove intersegment transactions.

(2) Merchant Energy revenues take into account the adoption of a consensus
    reached on EITF Issue No. 02-3, which requires us to report all physical
    sales of energy commodities in our energy trading activities on a net basis
    as a component of revenues. See Note 1 regarding the adoption of this Issue.

(3) Includes $322 million of assets that are classified as discontinued
    operations.

     The reconciliations of EBIT to income (loss) from continuing operations
before extraordinary items and cumulative effect of accounting changes are
presented below for each of the three years ended December 31:

<Table>
<Caption>
                                                            2002     2001      2000
                                                            -----    -----    ------
                                                                 (IN MILLIONS)
<S>                                                         <C>      <C>      <C>
Total EBIT for segments...................................  $ 269    $ 453    $1,470
Interest and debt expense.................................   (433)    (447)     (502)
Affiliated interest expense, net..........................     (9)     (46)       --
Returns on preferred interests of consolidated
  subsidiaries............................................    (35)     (51)      (60)
Income taxes..............................................     35      (81)     (253)
                                                            -----    -----    ------
          Income (loss) from continuing operations before
            extraordinary items and cumulative effect of
            accounting changes............................  $(173)   $(172)   $  655
                                                            =====    =====    ======
</Table>

     We had no customers whose revenues exceeded 10 percent of our total
revenues in 2002, 2001 and 2000.

                                        91
<PAGE>

19. SUPPLEMENTAL CASH FLOW INFORMATION

     The following table contains supplemental cash flow information for the
years ended December 31:

<Table>
<Caption>
                                                              2002     2001    2000
                                                              -----    ----    ----
                                                                  (IN MILLIONS)
<S>                                                           <C>      <C>     <C>
Interest paid...............................................  $ 517    $589    $389
Income tax payments (refunds)...............................     (1)     77      70
</Table>

20. 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 international pipelines, interstate pipelines, power generation
plants and gathering systems. Our investment balance was greater than our equity
in the net assets of these investments as of December 31, 2002 and 2001 by $39
million and $79 million. In 2002, the primary differences related to unamortized
purchase price adjustments and deferred taxes recorded on FERC regulated equity
investments. In 2001, the primary differences related to unamortized purchase
price adjustments and deferred taxes recorded on FERC regulated equity
investments. Our net ownership interest, investments in and advances to our
unconsolidated affiliates are as follows as of December 31:

<Table>
<Caption>
                                                                NET        INVESTMENTS      ADVANCES
                                                  TYPE OF    OWNERSHIP   ---------------   -----------
                                     COUNTRY     ENTITIES    INTEREST     2002     2001    2002   2001
                                    ---------   -----------  ---------   ------   ------   ----   ----
                                                                                 (IN MILLIONS)
<S>                                 <C>         <C>          <C>         <C>      <C>      <C>    <C>
United States
  Alliance Pipeline Limited
    Partnership(1)................                 LP(2)        2%       $   24   $  160   $ --   $--
  Aux Sable Liquid(3).............                 LP(2)       14%           --       58     --    --
  Bastrop Company, LLC............                LLC(4)       50%          121       99     --    --
  Eagle Point Cogeneration
    Partnership(5)................                 GP(6)       84%           --       85     --    --
  Great Lakes Gas
    Transmission(7)...............                             50%          312      297     --    --
  Midland Cogeneration Venture....                 LP(2)       44%          316      276     --    --
  Noric Holdings I, LLC(8)........                LLC(4)       42%          114      110     --    --
  Other Domestic Investments(9)...                           various        243      345     21    --
                                                                         ------   ------   ----   ---
         Total United States......                                        1,130    1,430     21    --
                                                                         ------   ------   ----   ---
Foreign
  EGE Fortuna.....................   Panama     Corporation    25%           61       56     --    --
  EGE Itabo.......................  Dominican   Corporation    25%           87      101     --    --
                                    Republic
  Habibullah Power................  Pakistan      LLC(4)       50%           57       53     99    --
  Saba Power Company..............  Pakistan      LLC(4)       94%           55       48     --    --
  Other Foreign Investments(9)....                           various        154      194     73    59
                                                                         ------   ------   ----   ---
         Total Foreign............                                          414      452    172    59
                                                                         ------   ------   ----   ---
         Total investments in and advances to unconsolidated
           affiliates.................................................   $1,544   $1,882   $193   $59
                                                                         ======   ======   ====   ===
</Table>

---------------
(1) We sold 12.3 percent interest in November 2002, and we sold the remaining of
    2.1 percent interest in March 2003.
(2) LP represents Limited Partnership.
(3) We sold 100 percent of our interest in November 2002.
(4) LLC represents Limited Liability Company.
(5) Consolidated in January 2002.
(6) GP represents General Partnership.
(7) 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.
(8) In June 2001, we conveyed natural gas and oil properties to an affiliate for
    an equity investment of 26 percent. In December 2001, we conveyed additional
    properties which increased our ownership percentage to 42 percent.
(9) Denotes investments less than $50 million.

                                        92
<PAGE>

     Earnings from our unconsolidated affiliates, including parent level
adjustments on these investees, asset impairments and realized gains or losses
on the sale of equity investments are as follows for the years ended December
31:

<Table>
<Caption>
                                                              2002    2001    2000
                                                              ----    ----    ----
                                                                 (IN MILLIONS)
<S>                                                           <C>     <C>     <C>
Alliance Pipeline Limited Partnership(1)....................  $ 21    $ 23    $ 12
Aux Sable Liquid............................................    (3)     (4)     (2)
Bastrop Company, LLC........................................    (5)     --      --
Eagle Point Cogeneration Partnership(2).....................    --      22      25
EGE Itabo...................................................    (2)      5       9
Great Lakes Gas Transmission................................    63      55      52
Habibullah Power............................................    10       2       9
Midland Cogeneration Venture................................    28      23      37
Noric Holdings I, LLC.......................................     4       4      --
Saba Power Company..........................................     7      --       1
Other.......................................................    32      93     122
                                                              ----    ----    ----
                                                               155     223     265
                                                              ----    ----    ----
Impairment charges and gains and losses on sales of
  investments...............................................   (51)     10      16
                                                              ----    ----    ----
          Total earnings from unconsolidated affiliates.....  $104    $233    $281
                                                              ====    ====    ====
</Table>

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

(1) We sold 12.3 percent interest in November 2002, and we sold the remaining of
    2.1 percent interest in March 2003.
(2) Consolidated in January 2002.

     Our impairment charges and gains and losses on sales of our investments
during 2002, 2001 and 2000 were as follows:

<Table>
<Caption>
                                          PRE-TAX                       CAUSE OF IMPAIRMENTS
INVESTMENT                              GAIN (LOSS)                        OR GAIN (LOSS)
----------                             -------------                    --------------------
                                       (IN MILLIONS)
<S>                                    <C>             <C>
2002
Aux Sable............................      $ (47)      Impairment generated as a result of the sale of
                                                       investment
Other................................         (4)
                                           -----
                                           $ (51)
                                           =====
2001
Deepwater Investors..................      $  13       Sale of investment to El Paso Energy Partners
Other................................         (3)
                                           -----
                                           $  10
                                           =====
2000
Guatemala Power......................      $  16       Sale of investment
                                           -----
                                           $  16
                                           =====
</Table>

     As discussed in Note 2, we have divested our ownership interest in the
Empire State, Iroquois, Stingray and U-T offshore pipeline systems in 2001.

                                        93
<PAGE>

     Summarized financial information of our proportionate share of
unconsolidated affiliates below 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. Our proportional shares of the unconsolidated affiliates in which we
hold a greater than 50 percent interest had net income of $23 million and $38
million for December 31, 2002 and 2001 and total assets of $443 million and $760
million for December 31, 2002 and 2001.

<Table>
<Caption>
                                                            YEAR ENDED DECEMBER 31,
                                                           --------------------------
                                                            2002      2001      2000
                                                           ------    ------    ------
                                                                  (UNAUDITED)
                                                                 (IN MILLIONS)
<S>                                                        <C>       <C>       <C>
Operating results data:
  Operating revenues.....................................  $1,194    $1,303    $4,103
  Operating expenses.....................................     928       959     3,837
  Income from continuing operations......................     129       200       247
  Net income.............................................     152       200       247
</Table>
<Table>
<Caption>
                                       DECEMBER 31,
                                     ----------------
                                      2002      2001
                                     ------    ------
                                       (UNAUDITED)
                                      (IN MILLIONS)
<S>                                  <C>       <C>
Financial position data:
  Current assets...................  $  609    $  576
  Non-current assets...............   2,635     3,508
  Short-term debt..................     244       228
  Other current liabilities........     241       249
  Long-term debt...................   1,084     1,524
  Other non-current liabilities....     170       279
  Equity in net assets.............   1,505     1,804
</Table>

     We have a 43.5 percent ownership interest, which consists of a 38.1 percent
general partner and a 5.4 percent limited partner interest in Midland
Cogeneration Venture Limited Partnership, a Michigan limited partnership that
qualifies as a significant subsidiary to the parent El Paso CGP Company.
Although we own a percentage of the general partner interest, we do not serve as
the operating partner. We participate in the decisions at the partnership but do
not have a controlling interest. Midland Cogeneration develops, owns and
operates a combined-cycle, gas-fired cogeneration facility in Midland.

     Summarized financial information of our proportionate share of Midland
Cogeneration Venture LP is as follows:

<Table>
<Caption>
                                                              YEAR ENDED DECEMBER 31,
                                                              -----------------------
                                                              2002     2001     2000
                                                              -----    -----    -----
                                                                    (UNAUDITED)
                                                                   (IN MILLIONS)
<S>                                                           <C>      <C>      <C>
Operating Results Data:
  Operating revenues........................................  $260     $266     $263
  Operating expenses........................................   178      197      170
  Income from continuing operations.........................    32       21       39
  Net income................................................    57       21       39
</Table>

                                        94
<PAGE>

<Table>
                                                                         AS OF
                                                                      DECEMBER 31,
                                                                      ------------
                                                                      2002    2001
                                                                      ----    ----
                                                                      (UNAUDITED)
                                                                          (IN
                                                                       MILLIONS)
<S>                                                           <C>     <C>     <C>
Financial Position Data:
  Current assets............................................          $155    $149
  Non-current assets........................................           758     772
  Short-term debt...........................................            41      81
  Other current liabilities.................................            50      58
  Long-term debt............................................           502     541
  Other non-current liabilities.............................             1       1
  Equity in net assets......................................           319     240
</Table>

     The following table shows revenues and charges from our unconsolidated
affiliates and El Paso's subsidiaries:

<Table>
<Caption>
                                                              2002     2001     2000
                                                             ------   ------   ------
                                                                  (IN MILLIONS)
<S>                                                          <C>      <C>      <C>
Revenues...................................................  $1,551   $2,090   $1,427
Cost of sales..............................................     278      194      317
Reimbursement for operating expenses.......................       3       11       11
Charges from affiliates....................................     341      335       --
Other income...............................................       6        8        7
</Table>

     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 various contractual agreements for trading
activities. Prior to October 2000, we had significant activities with Engage
Energy. During the fourth quarter of 2000, we terminated the Engage joint
venture and assumed the U.S. portion of Engage. In February 2001, we transferred
our natural gas and power trading activities to El Paso Merchant Energy, 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 period ended 2002 and 2001, we recognized
revenues with El Paso Merchant Energy of $1,124 million and $1,554 million which
were primarily with our Production segment. We had cost of sales of $198 million
and $111 million with El Paso Merchant Energy for 2002 and 2001. In addition,
other operational affiliated transactions have increased due to the El Paso
merger.

     El Paso has allocated a portion of its general and administrative expenses
to us since 2001. 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 2002 and 2001, the annual charges were
$146 million and $193 million. During 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 2002 and 2001, the annual charges were $40 million and
$34 million. El Paso also provides our production segment administrative and
other shared production services and allocated $155 million and $102 million in
2002 and 2001. We believe the allocation methods are reasonable.

 Related Party Transactions

     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 El Paso. Net
proceeds from these sales were $404 million, and we did not recognize a gain or
loss on the properties sold. The proceeds exceeded the net book value by $32
million and we recorded this proceeds as an increase to paid in capital.

                                        95
<PAGE>

     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 Corporation. 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.

     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. As of December 31, 2002 and
December 31, 2001, we had borrowed $2,374 million and $908 million. The market
rate of interest as of December 31, 2002 was 1.5% and at December 31, 2001, it
was 2.1%. In addition, we had a demand note receivable with El Paso of $199
million at December 31, 2002, at an interest rate of 2.2%. At December 31, 2001,
the demand note receivable was $120 million at an interest rate of 4.2%.

     At December 31, 2002 and December 31, 2001, we had accounts and notes
receivable from related parties of $346 million and $449 million. In addition,
we had a non-current note receivable from a related party of $126 million and
$27 million included in other non-current assets at December 31, 2002 and at
December 31, 2001.

     At December 31, 2002 and December 31, 2001, we had other accounts payable
to related parties of $87 million and $428 million. In addition, included in
short-term borrowings at December 31, 2001, was a current note payable to
related parties of $67 million.

21. SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

     Financial information by quarter is summarized below:

<Table>
<Caption>
                                                        QUARTERS ENDED
                                      ---------------------------------------------------
                                      DECEMBER 31    SEPTEMBER 30    JUNE 30    MARCH 31    TOTAL
                                      ------------   -------------   --------   ---------   ------
                                                             (IN MILLIONS)
<S>                                   <C>            <C>             <C>        <C>         <C>
2002(1)
  Operating revenues(2).............     $2,377         $1,648        $1,950     $2,555     $8,530
  Restructuring costs...............          5             --            --         --          5
  Gain (loss) on long-lived
     assets.........................        816             (1)          (13)       (11)       791
  Ceiling test charges..............          2             --           233         10        245
  Operating income (loss)(3)........       (672)            56            32        720        136
  Income (loss) from continuing
     operations before cumulative
     effect of accounting changes...       (531)           (20)          (35)       413       (173)
  Discontinued operations, net of
     income taxes...................         (2)           (36)          (67)       (19)      (124)
  Cumulative effect of accounting
     changes, net of income taxes...         --             --            14         --         14
  Net income (loss).................       (533)           (56)          (88)       394       (283)
2001(1)
  Operating revenues(4).............     $1,562         $1,951        $2,655     $2,556     $8,724
  Merger-related costs..............        (17)            10           203        618        814
  Gain (loss) on long-lived
     assets.........................          9              7             6        153        175
  Ceiling test charges..............         --            115            --         --        115
  Operating income (loss)(5)........        246            124            (7)      (305)        58
  Income (loss) from continuing
     operations before extraordinary
     items..........................        192             39           (65)      (338)      (172)
  Discontinued operations, net of
     income taxes...................         (4)             1            (3)         1         (5)
  Extraordinary items, net of income
     taxes..........................         --             (4)            3        (10)       (11)
  Net income (loss).................        188             36           (65)      (347)      (188)
</Table>

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

(1) Our coal mining operations are classified as discontinued operations. See
    Note 9 for further discussion.

                                        96
<PAGE>

(2) Our operating revenues differ from those previously reported in our March
    31, 2002 Form 10-Q by $2,397 million due to income statement
    reclassifications associated with our adoption of EITF Issue No. 02-3,
    discounted operations and other minor reclassifications, which had no impact
    on previously reported net income or stockholder's equity.
(3) Our operating income (loss) differs from that previously reported in our
    September 30, 2002, June 30, 2002 and March 31, 2002 Form 10-Q's by $1
    million, $12 million and $41 million due to income statement
    reclassifications associated with our discontinued operations,
    reclassifications of gains and losses on asset sales and asset impairments
    to operating income and other minor reclassifications which had no impact on
    previously reported net income or stockholder's equity.
(4) Our operating revenues differ from those previously reported in our
    September 30, 2001, June 30, 2001, and March 31, 2001 Form 10-Q's by $4,451
    million, $3,211 million and $5,306 million due to income statement
    reclassifications associated with our adoption of EITF Issue No. 02-3,
    discounted operations and other minor reclassifications, which had no impact
    on previously reported net income or stockholder's equity.
(5) Our operating income (loss) differs from that previously reported in our
    September 30, 2001, June 30, 2001, and March 31, 2001 Form 10-Q's by $2
    million, $41 million and $5 million due to income statement
    reclassifications associated with our discontinued operations,
    reclassification of gains and losses on asset sales and asset impairments to
    operating income and other minor reclassifications, which had no impact on
    previously reported net income or stockholder's equity.

22. SUPPLEMENTAL NATURAL GAS AND OIL OPERATIONS (UNAUDITED)

     At December 31, 2002, we had interests in natural gas and oil properties in
10 states and offshore operations and properties in federal and state waters in
the Gulf of Mexico. Internationally, we have a limited number of natural gas and
oil properties in Brazil, Canada, Hungary and Indonesia. We also have
exploration and production rights in Australia, Bolivia, Brazil, Canada, Hungary
and Indonesia.

     For purposes of the Supplemental Natural Gas and Oil Operations disclosure,
we have presented reserves, standardized measure of discounted future net cash
flows and the related changes in standardized measure separately for natural gas
systems operations which includes the natural gas and oil properties owned by
Colorado Interstate Gas Company and its subsidiaries that were sold in 2002. The
Supplemental Natural Gas and Oil Operations disclosure does not include any
value for storage gas and liquids volumes managed by our Pipelines segment.

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

<Table>
<Caption>
                                                       UNITED               OTHER
                                                       STATES   CANADA   COUNTRIES(1)   WORLDWIDE
                                                       ------   ------   ------------   ---------
                                                                     (IN MILLIONS)
<S>                                                    <C>      <C>      <C>            <C>
2002
  Natural gas and oil properties:
    Costs subject to amortization....................  $6,106    $608        $ 92        $6,806
    Costs not subject to amortization................     314     177         103           594
                                                       ------    ----        ----        ------
                                                        6,420     785         195         7,400
Less accumulated DD&A................................   3,222     435          44         3,701
                                                       ------    ----        ----        ------
Net capitalized costs................................  $3,198    $350        $151        $3,699
                                                       ======    ====        ====        ======
2001
  Natural gas and oil properties:
    Costs subject to amortization....................  $6,394    $415        $ 72        $6,881
    Costs not subject to amortization................     494     250          49           793
                                                       ------    ----        ----        ------
                                                        6,888     665         121         7,674
Less accumulated DD&A................................   2,316     170          31         2,517
                                                       ------    ----        ----        ------
Net capitalized costs................................  $4,572    $495        $ 90        $5,157
                                                       ======    ====        ====        ======
</Table>

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

(1) Includes International operations in Brazil, Hungary and Indonesia.

                                        97
<PAGE>

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

<Table>
<Caption>
                                                       UNITED               OTHER
                                                       STATES   CANADA   COUNTRIES(1)   WORLDWIDE
                                                       ------   ------   ------------   ---------
                                                                     (IN MILLIONS)
<S>                                                    <C>      <C>      <C>            <C>
2002
  Property acquisition costs
    Proved properties................................  $   23    $  6        $--         $   29
    Unproved properties..............................      12       7         10             29
  Exploration costs..................................      49      70         45            164
  Development costs..................................     717      80          3            800
                                                       ------    ----        ---         ------
         Total costs incurred                          $  801    $163        $58         $1,022
                                                       ======    ====        ===         ======
2001
  Property acquisition costs
    Proved properties................................  $   87    $232        $--         $  319
    Unproved properties..............................      33      16         25             74
  Exploration costs..................................     110      19         58            187
  Development costs..................................   1,026     105         14          1,145
                                                       ------    ----        ---         ------
         Total costs incurred                          $1,256    $372        $97         $1,725
                                                       ======    ====        ===         ======
2000
  Property acquisition costs
    Proved properties................................  $  127    $  3        $--         $  130
    Unproved properties..............................     130       6         --            136
  Exploration costs..................................     193      42         11            246
  Development costs..................................     960      69         --          1,029
                                                       ------    ----        ---         ------
         Total costs incurred                          $1,410    $120        $11         $1,541
                                                       ======    ====        ===         ======
</Table>

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

(1) Includes International operations in Brazil, Hungary and Indonesia.

     In our January 1, 2003 reserve report, the amounts estimated to be spent in
2003, 2004 and 2005 to develop our worldwide booked proved undeveloped reserves
are $323 million, $282 million and $88 million.

     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, 2002, pending determination of proved reserves. Capitalized
interest of $13 million, $17 million, and $7 million for the years ended
December 31, 2002, 2001 and 2000 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,
                                           ------------   ------------------   ------------
                                               2002       2002   2001   2000       1999
                                           ------------   ----   ----   ----   ------------
<S>                                        <C>            <C>    <C>    <C>    <C>
Worldwide(1)
  Acquisition............................      $296       $ 47   $131   $ 66       $ 52
  Exploration............................       144         97     15     27          5
  Development............................       154         10     95     26         23
                                               ----       ----   ----   ----       ----
                                               $594       $154   $241   $119       $ 80
                                               ====       ====   ====   ====       ====
</Table>

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

(1) Includes operations in the United States, Brazil, Canada, Hungary and
    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 2003 through 2006. Total amortization
expense per Mcfe, including ceiling test charges, was $2.20, $1.29, and $1.05 in
2002, 2001, and 2000. Excluding ceiling test charges, amortization expense would
have been $1.44 per Mcfe in 2002. Depreciation, depletion, and amortization
excludes provisions for the impairment of international projects of $15 million
in 2000.

                                        98
<PAGE>

     Net quantities of proved developed and undeveloped reserves of natural gas
and liquids, including condensate and crude oil, and changes in these reserves
are presented below. Information in this table is based on the reserve report
dated January 1, 2003, prepared internally by Production and reviewed by
Huddleston & Co., Inc. 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, acquisition, property sales, necessary
reserve revisions and additions to reflect actual experience. These reserves
include 465,783 MMcfe of production delivery commitments under financing
arrangements that extend through 2042. The financing arrangement supported by
these reserves matures in 2006. Total proved reserves on the fields with this
dedicated production were 919,265 MMcfe.

<Table>
<Caption>
                                                                NATURAL GAS (IN Bcf)
                                               -------------------------------------------------------
                                                                                             NATURAL
                                               UNITED               OTHER                      GAS
                                               STATES   CANADA   COUNTRIES(1)   WORLDWIDE   SYSTEMS(2)
                                               ------   ------   ------------   ---------   ----------
<S>                                            <C>      <C>      <C>            <C>         <C>
Net proved developed and undeveloped
  reserves(3)
  January 1, 2000............................   3,269      73         --          3,342         198
     Revisions of previous estimates.........    (203)    (62)        --           (265)         11
     Extensions, discoveries and other.......     802     155         91          1,048          --
     Purchases of reserves in place..........     499       2         --            501          --
     Sales of reserves in place..............     (19)     --         --            (19)         --
     Production..............................    (328)     (1)        --           (329)        (33)
                                               ------    ----        ---         ------        ----
  December 31, 2000..........................   4,020     167         91          4,278         176
     Revisions of previous estimates.........    (996)   (136)       (51)        (1,183)         42
     Extensions, discoveries and other.......     604      85         --            689          --
     Purchases of reserves in place..........     103      83         --            186          --
     Sales of reserves in place..............      --      --         --             --          --
     Production..............................    (373)    (13)        --           (386)        (35)
                                               ------    ----        ---         ------        ----
  December 31, 2001..........................   3,358     186         40          3,584         183
     Revisions of previous estimates.........    (169)    (70)        31           (208)         --
     Extensions, discoveries and other.......     195      56          5            256          --
     Purchases of reserves in place..........      --       5         --              5          --
     Sales of reserves in place..............  (1,569)    (30)        --         (1,599)       (183)
     Production..............................    (247)    (17)        --           (264)         --
                                               ------    ----        ---         ------        ----
  December 31, 2002..........................   1,568     130         76          1,774          --
                                               ======    ====        ===         ======        ====
Proved developed reserves
     December 31, 2000.......................   1,816     112         --          1,928         176
     December 31, 2001.......................   1,613     138         --          1,751         183
     December 31, 2002.......................     969     104         --          1,073          --
</Table>

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

(1) Includes International operations in Brazil, Hungary and Indonesia.

(2) Includes natural gas and oil properties owned by Colorado Interstate Gas
    Company and its subsidiaries that were sold in 2002.

(3) Net proved reserves exclude royalties and interests owned by others and
    reflects contractual arrangements and royalty obligations in effect at the
    time of the estimate.

                                        99
<PAGE>

<Table>
<Caption>
                                                                    LIQUIDS(1)(IN MBbls)
                                                  --------------------------------------------------------
                                                                                                 NATURAL
                                                  UNITED                OTHER                      GAS
                                                  STATES    CANADA   COUNTRIES(2)   WORLDWIDE   SYSTEMS(3)
                                                  -------   ------   ------------   ---------   ----------
<S>                                               <C>       <C>      <C>            <C>         <C>
Net proved developed and undeveloped reserves(4)
  January 1, 2000...............................   56,878      867          --        57,745        249
     Revisions of previous estimates............      238     (544)         --          (306)         7
     Extensions, discoveries and other..........    8,231    3,600       4,862        16,693         --
     Purchases of reserves in place.............    6,546       13          --         6,559         --
     Sales of reserves in place.................     (609)      --          --          (609)        --
     Production.................................   (6,477)     (13)         --        (6,490)       (25)
                                                  -------   ------      ------       -------       ----
  December 31, 2000.............................   64,807    3,923       4,862        73,592        231
     Revisions of previous estimates............   25,140   (4,224)     (4,862)       16,054       (118)
     Extensions, discoveries and other..........   24,843    1,173       7,771        33,787         --
     Purchases of reserves in place.............      101   10,570          --        10,671         --
     Production.................................   (8,227)    (560)         --        (8,787)       (16)
                                                  -------   ------      ------       -------       ----
  December 31, 2001.............................  106,664   10,882       7,771       125,317         97
     Revisions of previous estimates............  (32,823)  (1,798)     (5,660)      (40,281)        --
     Extensions, discoveries and other..........    4,565      282      10,541        15,388         --
     Purchases of reserves in place.............       --      362          --           362         --
     Sales of reserves in place.................   (4,998)  (2,535)         --        (7,533)       (97)
     Production.................................   (6,928)  (1,053)         --        (7,981)        --
                                                  -------   ------      ------       -------       ----
  December 31, 2002.............................   66,480    6,140      12,652        85,272         --
                                                  =======   ======      ======       =======       ====
Proved developed reserves
     December 31, 2000..........................   36,404    2,723          --        39,127        231
     December 31, 2001..........................   62,704    7,341          --        70,045         97
     December 31, 2002..........................   40,621    4,446          --        45,067         --
</Table>

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

(1) Includes oil, condensate and natural gas liquids.
(2) Includes International operations in Brazil, Hungary and Indonesia.
(3) Includes natural gas and oil properties owned by Colorado Interstate Gas
    Company and its subsidiaries that were sold in 2002.
(4) Net proved reserves exclude royalties and interests owned by others and
    reflects contractual arrangements and royalty obligations in effect at the
    time of the estimate.

     There are numerous 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 significant changes to reserves, other than purchases, sales or
production, are due to reservoir performance in existing fields and from
drilling additional wells in existing fields. 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, 2002.

                                       100
<PAGE>

     Results of operations from producing activities by fiscal year were as
follows at December 31 (in millions):

<Table>
<Caption>
                                                       UNITED                OTHER
                                                       STATES    CANADA   COUNTRIES(1)   WORLDWIDE
                                                       ------    ------   ------------   ---------
<S>                                                    <C>       <C>      <C>            <C>
2002
Net Revenues
  Sales to external customers........................  $  241    $  47        $ --        $  288
  Affiliated sales...................................     886       20          --           906
                                                       ------    -----        ----        ------
         Total.......................................   1,127       67          --         1,194
Production costs(2)..................................    (163)     (18)         (1)         (182)
Depreciation, depletion and amortization.............    (421)     (28)         --          (449)
Ceiling test charges.................................      --     (226)        (10)         (236)
Loss on sale of assets(3)............................    (702)      --          --          (702)
                                                       ------    -----        ----        ------
                                                         (159)    (205)        (11)         (375)
Income tax benefit...................................      58       83           4           145
                                                       ------    -----        ----        ------
Results of operations from producing activities......  $ (101)   $(122)       $ (7)       $ (230)
                                                       ======    =====        ====        ======
2001
Net Revenues
  Sales to external customers........................  $  391    $  45        $ --        $  436
  Affiliated sales...................................   1,484        1          --         1,485
                                                       ------    -----        ----        ------
         Total.......................................   1,875       46          --         1,921
Production costs(2)..................................    (210)     (12)         --          (222)
Depreciation, depletion and amortization.............    (435)     (17)         --          (452)
Ceiling test charges.................................      --      (87)        (28)         (115)
                                                       ------    -----        ----        ------
                                                        1,230      (70)        (28)        1,132
Income tax (expense) benefit.........................    (430)      25          (9)         (414)
                                                       ------    -----        ----        ------
Results of operations from producing activities......  $  800    $ (45)       $(37)       $  718
                                                       ======    =====        ====        ======
2000
Net Revenues
  Sales to external customers........................  $  867    $   6        $ --        $  873
  Affiliated sales...................................     214       --          --           214
                                                       ------    -----        ----        ------
         Total.......................................   1,081        6          --         1,087
Production costs(2)..................................    (236)      (1)         --          (237)
Depreciation, depletion and amortization.............    (372)      (1)         --          (373)
                                                       ------    -----        ----        ------
                                                          473        4          --           477
Income tax expense...................................    (160)      (2)         --          (162)
                                                       ------    -----        ----        ------
Results of operations from producing activities......  $  313    $   2        $ --        $  315
                                                       ======    =====        ====        ======
</Table>

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

(1) Includes international operations in Brazil, Hungary and Indonesia.
(2) Production costs include direct lifting costs (labor, repairs and
    maintenance materials and supplies) and the administrative costs of field
    offices, insurance and property and severance taxes.
(3) We recognized a loss of $702 million, or $452 million net of tax, on the
    sale of natural gas and oil properties in Utah. A loss was recognized on
    this sale because the reserves sold exceeded 25 percent of our total
    reserves and significantly altered the relationship between capitalized
    costs and proved reserves.

                                       101
<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>
                                                                                         NATURAL
                                          UNITED                OTHER                      GAS
                                          STATES    CANADA   COUNTRIES(1)   WORLDWIDE   SYSTEMS(2)
                                          -------   ------   ------------   ---------   ----------
<S>                                       <C>       <C>      <C>            <C>         <C>
2002
Future cash inflows(3)..................  $ 8,625   $ 671       $ 542        $ 9,838      $  --
Future production costs.................   (1,418)   (127)       (124)        (1,669)        --
Future development costs................   (1,022)    (16)       (133)        (1,171)        --
Future income tax expenses..............   (1,585)    (21)        (50)        (1,656)        --
                                          -------   ------      -----        -------      -----
Future net cash flows...................    4,600     507         235          5,342         --
10% annual discount for estimated timing
  of cash flows.........................   (1,822)   (220)       (127)        (2,169)        --
                                          -------   ------      -----        -------      -----
Standardized measure of discounted
  future net cash flows.................  $ 2,778   $ 287       $ 108        $ 3,173      $  --
                                          =======   ======      =====        =======      =====
Standardized measure of discontinued
  future net cash flows, including
  effects of hedging activities.........  $ 2,718   $ 287       $ 108        $ 3,113      $  --
                                          =======   ======      =====        =======      =====
2001
Future cash inflows(4)..................  $ 9,815   $ 641       $ 253        $10,709      $ 313
Future production costs.................   (1,691)   (196)        (51)        (1,938)       (34)
Future development costs................   (1,391)    (83)        (73)        (1,547)       (30)
Future income tax expenses..............   (1,436)     (8)        (23)        (1,467)       (83)
                                          -------   ------      -----        -------      -----
Future net cash flows...................    5,297     354         106          5,757        166
10% annual discount for estimated timing
  of cash flows.........................   (2,347)   (143)        (52)        (2,542)       (72)
                                          -------   ------      -----        -------      -----
Standardized measure of discounted
  future net cash flows.................  $ 2,950   $ 211       $  54        $ 3,215      $  94
                                          =======   ======      =====        =======      =====
Standardized measure of discounted
  future net cash flows, including
  effects of hedging activities.........  $ 3,361   $ 211       $  54        $ 3,626      $  94
                                          =======   ======      =====        =======      =====
2000
Future cash inflows(5)..................  $27,535   $1,597      $ 397        $29,529      $ 474
Future production costs.................   (3,767)   (136)        (70)        (3,973)       (59)
Future development costs................   (1,297)    (35)       (139)        (1,471)       (51)
Future income tax expenses..............   (7,014)   (599)        (60)        (7,673)      (116)
                                          -------   ------      -----        -------      -----
Future net cash flows...................   15,457     827         128         16,412        248
10% annual discount for estimated timing
  of cash flows.........................   (6,522)   (469)       (109)        (7,100)       (89)
                                          -------   ------      -----        -------      -----
Standardized measure of discounted
  future net cash flows.................  $ 8,935   $ 358       $  19        $ 9,312      $ 159
                                          =======   ======      =====        =======      =====
Standardized measure of discounted
  future net cash flows, including
  effects of hedging activities.........  $ 8,590   $ 358       $  19        $ 8,967      $ 159
                                          =======   ======      =====        =======      =====
</Table>

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

(1) Includes international operations in Brazil, Hungary and Indonesia.
(2) Includes natural gas and oil properties owned by Colorado Interstate Gas
    Company and its subsidiaries that were sold in 2002.
(3) Excludes $111 million of future cash outflows attributable to hedging
    activities.
(4) Excludes $684 million of future cash inflows attributable to hedging
    activities.
(5) Excludes $555 million of future cash outflows attributable to hedging
    activities.

                                       102
<PAGE>

     For the calculations in the preceding table, estimated future cash inflows
from estimated future production of proved reserves were computed using year-end
market natural gas and oil prices. 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.

     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 (in millions):

<Table>
<Caption>
                                                                    YEARS ENDED DECEMBER 31,(1)
                                              -----------------------------------------------------------------------
                                                  2002                   2001                         2000
                                              -------------   --------------------------   --------------------------
                                               EXPLORATION     EXPLORATION     NATURAL      EXPLORATION     NATURAL
                                                   AND             AND           GAS            AND           GAS
                                              PRODUCTION(2)   PRODUCTION(2)   SYSTEMS(3)   PRODUCTION(2)   SYSTEMS(3)
                                              -------------   -------------   ----------   -------------   ----------
<S>                                           <C>             <C>             <C>          <C>             <C>
Sales and transfers of natural gas and oil
  produced net of production costs..........     $(1,011)        $(1,697)       $(255)        $(1,300)        $(52)
Net changes in prices and production
  costs.....................................       3,652          (8,160)          10           6,697          150
Extensions, discoveries and improved
  recovery, less related costs..............         568             766           --           3,586           --
Changes in estimated future development
  costs.....................................        (362)            (20)          13              --           --
Previously estimated development costs
  incurred during the period................         258             337           --              83           --
Revisions of previous quantity estimates....        (884)         (1,085)          39            (693)          34
Accretion of discount.......................         387           1,308           23             194            4
Net change in income taxes..................        (237)          3,098           25          (3,337)         (42)
Purchases of reserves in place..............          13             222           --           1,292           --
Sales of reserves in place..................      (2,962)             --           --             (14)          --
Changes in production rates, timing and
  other.....................................         536            (866)          80              49           --
                                                 -------         -------        -----         -------         ----
  Net change................................     $   (42)        $(6,097)       $ (65)        $ 6,557         $ 94
                                                 =======         =======        =====         =======         ====
</Table>

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

(1) This disclosure reflects the change in standardized measure excluding the
    effects of hedging activities.
(2) Includes operations in the United States, Canada, Brazil, Hungary and
    Indonesia.
(3) Includes natural gas and oil properties owned by Colorado Interstate Gas
    Company and its subsidiaries that were sold in 2002.

                                       103
<PAGE>

                       REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and Stockholder of
El Paso CGP Company

     In our opinion, the consolidated financial statements 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, 2002 and 2001, and the consolidated results of their
operations and their cash flows for each of the two years in the period ended
December 31, 2002 in conformity with accounting principles generally accepted in
the United States of America. In addition, in our opinion, the financial
statement schedule for each of the two years in the period ended December 31,
2002 listed in the index 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 auditing standards generally accepted in the
United States of America, which 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 Company adopted Statement of Financial
Accounting Standards No. 142, Goodwill and Other Intangible Assets and Statement
of Financial Accounting Standards 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 in the second quarter
of 2002, and EITF Issue No. 02-3, Accounting for Contracts Involved in Energy
Trading and Risk Management Activities, Consensus 1 and 2; in the third and
fourth quarter of 2002, respectively.

     As discussed in Notes 1 and 11, the Company adopted Statement of Financial
Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging
Activities, on January 1, 2001.

     We also audited the adjustments described in Note 18 that were applied to
restate the disclosures of 2000 segment information in the accompanying
consolidated financial statements to give retroactive effect to the change in
reportable segments. In our opinion, such adjustments are appropriate and have
been properly applied to the prior period consolidated financial statements.

     As discussed in Note 17, during 2001, the Company changed the measurement
date used to account for pension and postretirement benefits other than pensions
from December 31 to September 30.

/s/ PRICEWATERHOUSECOOPERS LLP

Houston, Texas
March 28, 2003

                                       104
<PAGE>

                          INDEPENDENT AUDITORS' REPORT

Board of Directors and Stockholder of
El Paso CGP Company
Houston, Texas

     We have audited the consolidated statements of income, stockholders'
equity, cash flows and comprehensive income of El Paso CGP Company (formerly The
Coastal Corporation) and subsidiaries, for the year ended December 31, 2000. Our
audit also included the financial statement schedule listed in the Index at Item
15(a)2. These financial statements and financial statement schedule are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audit.

     We conducted our audit in accordance with auditing standards generally
accepted in the United States of America. Those 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. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.

     In our opinion, such consolidated financial statements present fairly, in
all material respects, the El Paso CGP Company's results of operations and cash
flows for the year ended December 31, 2000, in conformity with accounting
principles generally accepted in the United States of America. Also, in our
opinion, such financial statement schedule, when considered in relation to the
basic consolidated financial statements taken as a whole, presents fairly in all
material respects the information set forth therein.

/s/ Deloitte & Touche LLP

Houston, Texas
March 19, 2001
(March 28, 2003 as to the effects of reclassifications related to the adoption
of net reporting for trading activities and discontinued operations as discussed
in notes 1 and 9, respectively)

                                       105
<PAGE>

                                  SCHEDULE II

                      EL PASO CGP COMPANY AND SUBSIDIARIES

                       VALUATION AND QUALIFYING ACCOUNTS
                  YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
                                 (IN MILLIONS)

<Table>
<Caption>
                                                 CHARGED TO
                                    BALANCE AT   COSTS AND                                       BALANCE
                                    BEGINNING     EXPENSES      CHARGED TO                       AT END
           DESCRIPTION              OF PERIOD    AND OTHER    OTHER ACCOUNTS   DEDUCTIONS       OF PERIOD
           -----------              ----------   ----------   --------------   ----------       ---------
<S>                                 <C>          <C>          <C>              <C>              <C>
2002
  Allowance for doubtful
     accounts.....................     $ 36         $  7           $  4           $(10)(1)        $ 37
  Legal reserves..................       81           10             13            (49)(2)          55
  Environmental reserves..........      260           14            (95)(6)        (23)            156
  Provision for refund............        5            7             --             (8)              4
  Planned major maintenance
     accrual......................       36           20             --            (16)             40
2001
  Allowance for doubtful
     accounts.....................     $ 19         $ 23           $ --           $ (6)(1)        $ 36
  Legal reserves..................       32           50(3)          --             (1)             81
  Environmental reserves..........       28          242(3)          --            (10)            260
  Provision for refund............       --            5             --             --               5
  Planned major maintenance
     accrual......................       51           (1)(4)         --            (14)             36
2000
  Allowance for doubtful
     accounts.....................     $ 32         $  3           $(14)          $ (2)(1)        $ 19
  Legal reserves..................       48          (14)(5)         --             (2)             32
  Environmental reserves..........       27           10             --             (9)             28
  Provision for refund............        8            2             --            (10)             --
  Planned major maintenance
     accrual......................       34           33             --            (16)             51
</Table>

---------------
(1) Primarily accounts written off.
(2) Payments for various litigation reserves.
(3) These amounts primarily relate to additional liabilities recorded in
    connection with changes in our estimates of these liabilities. See Note 5
    for a further discussion of this change.
(4) During 2001, we accrued $23 million of reserves. In June, we leased our
    Corpus Christi refinery to Valero, and as a result we reversed $24 million
    of reserves.
(5) Includes reversal of $16 million of legal reserves due to a favorable
    resolution of natural gas price-related contingencies.
(6) In November 2002, we sold Coastal Mart Inc to an affiliate of El Paso
    Corporation which included environmental reserves of $95 million.

                                       106
<PAGE>

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
        FINANCIAL DISCLOSURE.

     None.

                                    PART III

     Item 10, "Directors and Executive Officers of the Registrant;" Item 11,
"Executive Compensation;" Item 12, "Security Ownership of Certain Beneficial
Owners and Management;" and Item 13, "Certain Relationships and Related
Transactions," have been omitted from this report pursuant to the reduced
disclosure format permitted by General Instruction I to Form 10-K.

ITEM 14. CONTROLS AND PROCEDURES

     Evaluation of Controls and Procedures.  Under the supervision and with the
participation of management, including our principal executive officer and
principal financial officer, we have evaluated the effectiveness of the design
and operation of our disclosure controls and procedures (Disclosure Controls)
and internal controls (Internal Controls) within 90 days of the filing date of
this annual report pursuant to Rules 13a-15 and 15d-15 under the Securities
Exchange Act of 1934 (Exchange Act).

     Definition of Disclosure Controls and Internal Controls.  Disclosure
Controls are our controls and other procedures that are designed to ensure that
information required to be disclosed by us in the reports that we file or submit
under the Exchange Act is recorded, processed, summarized and reported, within
the time periods specified under the Exchange Act. Disclosure Controls include,
without limitation, controls and procedures designed to ensure that information
required to be disclosed by us in the reports that we file under the Exchange
Act is accumulated and communicated to our management, including our principal
executive officer and principal financial officer, as appropriate to allow
timely decisions regarding required disclosure. Internal Controls are procedures
which are designed with the objective of providing reasonable assurance that (1)
our transactions are property authorized; (2) our assets are safeguarded against
unauthorized or improper use; and (3) our transactions are properly recorded and
reported, all to permit the preparation of our financial statements in
conformity with generally accepted accounting principles.

     Limitations on the Effectiveness of Controls.  El Paso CGP Company's
management, including the principal executive officer and principal financial
officer, does not expect that our Disclosure Controls and Internal Controls will
prevent all errors and all fraud. A control system, no matter how well conceived
and operated, can provide only reasonable, not absolute, assurance that the
objectives of the control system are met. Further, the design of a control
system must reflect the fact that there are resource constraints, and the
benefits of controls must be considered relative to their costs. Because of the
inherent limitations in all control systems, no evaluation of controls can
provide absolute assurance that all control issues and instances of fraud, if
any, within the company have been detected. These inherent limitations include
the realities that judgments in decision-making can be faulty, and that
breakdowns can occur because of simple errors or mistakes. Additionally,
controls can be circumvented by the individual acts of some persons, by
collusion of two or more people, or by management override of the controls. The
design of any system of controls also is based in part upon certain assumptions
about the likelihood of future events, and there can be no assurance that any
design will succeed in achieving its stated goals under all potential future
conditions; over time, control may become inadequate because of changes in
conditions, or the degree of compliance with the policies or procedures may
deteriorate. Because of the inherent limitations in a cost-effective control
system, misstatements due to error or fraud may occur and not be detected.

     No Significant Changes in Internal Controls.  We have sought to determine
whether there were any "significant deficiencies" or "material weaknesses" in El
Paso CGP Company's Internal Controls, or whether the company had identified any
acts of fraud involving personnel who have a significant role in El Paso CGP
Company's Internal Controls. This information was important both for the
controls evaluation generally and because the principal executive officer and
principal financial officer are required to disclose that information to our
Board's Audit Committee and our independent auditors and to report on related
matters in this section

                                       107
<PAGE>

of the Annual Report. The principal executive officer and principal financial
officer note that, from the date of the controls evaluation to the date of this
Annual Report, there have been no significant changes in Internal Controls or in
other factors that could significantly affect Internal Controls, including any
corrective actions with regard to significant deficiencies and material
weaknesses.

     Effectiveness of Disclosure Controls.  Based on the controls evaluation,
our principal executive officer and principal financial officer have concluded
that, subject to the limitations discussed above, the Disclosure Controls are
effective to ensure that material information relating to El Paso CGP Company's
and its consolidated subsidiaries is made known to management, including the
principal executive officer and principal financial officer, particularly during
the period when our periodic reports are being prepared.

     Officer Certification.  The certifications from the principal executive
officer and principal financial officer required under Sections 302 and 906 of
the Sarbanes-Oxley Act of 2002 have been included herein, or as Exhibits to this
Annual Report, as appropriate.

                                    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...........................   46
Consolidated Balance Sheets.................................   47
Consolidated Statements of Cash Flows.......................   49
Consolidated Statements of Stockholders' Equity.............   50
Condensed Consolidated Statements of Comprehensive Income...   51
Notes to Consolidated Financial Statements..................   52
Report of Independent Accountants...........................  105
Independent Auditors' Report................................  106
</Table>

     The following financial statements of our equity investments are included
on the following pages of this report:

<Table>
<Caption>
                                                              PAGE
                                                              ----
<S>                                                           <C>
Great Lakes Gas Transmission Limited Partnership
  Independent Auditors' Report..............................  111
  Consolidated Statements of Income and Partners' Capital...  112
  Consolidated Balance Sheets...............................  113
  Consolidated Statements of Cash Flows.....................  114
  Notes to Consolidated Financial Statements................  115
</Table>

     2. Financial statement schedules and supplementary information required to
be submitted.

<Table>
<Caption>
                                                              PAGE
                                                              ----
<S>                                                           <C>
Schedule II  -- Valuation and qualifying accounts...........  107
</Table>

          Schedules other than those listed above are omitted because they are
     not applicable.

<Table>
<Caption>
                                                              PAGE
                                                              ----
<S>                                                           <C>  <C>
3. Exhibit list.............................................  119
</Table>

                                       108
<PAGE>

                GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP

                              FINANCIAL STATEMENTS
                       WITH INDEPENDENT AUDITORS' REPORT
                               DECEMBER 31, 2002

                                       109
<PAGE>

                          INDEPENDENT AUDITORS' REPORT

The Partners and Management Committee
Great Lakes Gas Transmission Limited Partnership:

     We have audited the accompanying consolidated balance sheets of Great Lakes
Gas Transmission Limited Partnership and subsidiary (Partnership) as of December
31, 2002 and 2001, and the related consolidated statements of income and
partners' capital, and cash flows for each of the years in the three year period
ended December 31, 2002. These consolidated financial statements are the
responsibility of the Partnership's management. Our responsibility is to express
an opinion on these consolidated financial statements based on our audits.

     We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those 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. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

     In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Great Lakes
Gas Transmission Limited Partnership and subsidiary as of December 31, 2002 and
2001, and the results of their operations and their cash flows for each of the
years in the three year period ended December 31, 2002 in conformity with
accounting principles generally accepted in the United States of America.

/s/ KPMG LLP

Detroit, Michigan
January 8, 2003

                                       110
<PAGE>

                GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP

            CONSOLIDATED STATEMENTS OF INCOME AND PARTNERS' CAPITAL

<Table>
<Caption>
                                                                YEARS ENDED DECEMBER 31,
                                                            ---------------------------------
                                                              2002        2001        2000
                                                            ---------   ---------   ---------
                                                                 (THOUSANDS OF DOLLARS)
<S>                                                         <C>         <C>         <C>
Transportation Revenues...................................  $ 277,515   $ 276,872   $ 282,636
Operating Expenses
  Operation and Maintenance...............................     37,075      32,662      39,807
  Depreciation............................................     56,916      56,640      60,705
  Income Taxes Payable by Partners........................     45,400      39,950      39,518
  Property and Other Taxes................................     14,393      28,828      29,322
                                                            ---------   ---------   ---------
                                                              153,784     158,080     169,352
                                                            ---------   ---------   ---------
Operating Income..........................................    123,731     118,792     113,284
Other Income (Expense)
  Interest on Long Term Debt..............................    (44,539)    (47,960)    (47,474)
  Allowance for Funds Used During Construction............        500         464         769
  Other, Net..............................................      3,350       2,511       5,935
                                                            ---------   ---------   ---------
                                                              (40,689)    (44,985)    (40,770)
                                                            ---------   ---------   ---------
Net Income................................................  $  83,042   $  73,807   $  72,514
                                                            =========   =========   =========
Partners' Capital
  Balance at Beginning of Year............................  $ 443,640   $ 449,237   $ 604,838
  Contributions by General Partners.......................     25,432      21,226      19,290
  Net Income..............................................     83,042      73,807      72,514
  Current Income Taxes Payable by Partners Charged to
     Earnings.............................................     27,801      23,378      24,548
  Distributions to Partners...............................   (134,403)   (124,008)   (271,953)
                                                            ---------   ---------   ---------
  Balance at End of Year..................................  $ 445,512   $ 443,640   $ 449,237
                                                            =========   =========   =========
</Table>

        The accompanying notes are an integral part of these statements.

                                       111
<PAGE>

                GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP

                          CONSOLIDATED BALANCE SHEETS

<Table>
<Caption>
                                                                AS OF DECEMBER 31,
                                                              -----------------------
                                                                 2002         2001
                                                              ----------   ----------
                                                              (THOUSANDS OF DOLLARS)
<S>                                                           <C>          <C>
ASSETS
Current Assets
  Cash and Temporary Cash Investments.......................  $   30,752   $   40,320
  Receivable from Limited Partner...........................          --        1,922
  Accounts Receivable.......................................      35,395       29,145
  Materials and Supplies, at Average Cost...................       9,906       10,035
  Regulatory Assets.........................................         515          566
  Prepayments and Other.....................................       4,431        4,403
                                                              ----------   ----------
                                                                  80,999       86,391
                                                              ----------   ----------
Gas Utility Plant
  Property, Plant and Equipment.............................   1,993,249    1,965,442
  Less Accumulated Depreciation.............................     822,763      772,832
                                                              ----------   ----------
                                                               1,170,486    1,192,610
                                                              ----------   ----------
                                                              $1,251,485   $1,279,001
                                                              ==========   ==========

LIABILITIES & PARTNERS' CAPITAL
Current Liabilities
  Current Maturities of Long Term Debt......................  $   24,000   $   36,500
  Accounts Payable..........................................      16,492       14,344
  Payable to Limited Partner................................         562           --
  Property and Other Taxes..................................      26,764       27,895
  Accrued Interest and Other................................      12,757       13,421
                                                              ----------   ----------
                                                                  80,575       92,160
                                                              ----------   ----------
Long Term Debt..............................................     497,500      532,250
Other Liabilities
  Amounts Equivalent to Deferred Income Taxes...............     224,298      206,057
  Regulatory Liabilities....................................       2,454        3,870
  Other.....................................................       1,146        1,024
                                                              ----------   ----------
                                                                 227,898      210,951
                                                              ----------   ----------
Partners' Capital...........................................     445,512      443,640
                                                              ----------   ----------
                                                              $1,251,485   $1,279,001
                                                              ==========   ==========
</Table>

        The accompanying notes are an integral part of these statements.

                                       112
<PAGE>

                GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP

                     CONSOLIDATED STATEMENTS OF CASH FLOWS

<Table>
<Caption>
                                                                  YEARS ENDED DECEMBER 31,
                                                              --------------------------------
                                                                2002        2001        2000
                                                              ---------   ---------   --------
                                                                   (THOUSANDS OF DOLLARS)
<S>                                                           <C>         <C>         <C>
Cash Flow Increase (Decrease) from:
Operating Activities
  Net Income................................................  $  83,042   $  73,807   $ 72,514
  Adjustments to Reconcile Net Income to Operating Cash
     Flows:
     Depreciation...........................................     56,916      56,640     60,705
     Amounts Equivalent to Deferred Income Taxes............     18,241      12,918     15,411
     Regulatory Assets......................................         51       6,950      1,209
     Regulatory Liabilities.................................     (1,416)     (1,417)    (1,452)
     Allowance for Funds Used During Construction...........       (500)       (464)      (769)
     Changes in Current Assets and Liabilities:
       Accounts Receivable..................................     (6,250)      6,166     (1,289)
       Accounts Payable.....................................      2,148      (5,667)    (1,205)
       Property and Other Taxes.............................     (1,131)     (1,445)    (1,689)
       Other................................................      2,043      (9,630)       (52)
                                                              ---------   ---------   --------
                                                                153,144     137,858    143,383
Investment in Utility Plant.................................    (34,292)    (31,574)   (33,372)
Financing Activities
  Issuance of Long Term Debt................................         --          --    100,000
  Repayment of Long Term Debt...............................    (47,250)    (26,500)   (17,800)
  Contributions by Partners.................................     25,432      21,226     19,290
  Current Income Taxes Payable by Partners Charged to
     Earnings...............................................     27,801      23,378     24,548
  Distributions to Partners.................................   (134,403)   (124,008)  (271,953)
                                                              ---------   ---------   --------
                                                               (128,420)   (105,904)  (145,915)
                                                              ---------   ---------   --------
Change in Cash and Cash Equivalents.........................     (9,568)        380    (35,904)
Cash and Cash Equivalents:
  Beginning of Year.........................................     40,320      39,940     75,844
                                                              ---------   ---------   --------
  End of Year...............................................  $  30,752   $  40,320   $ 39,940
                                                              =========   =========   ========
Supplemental Disclosure of Cash Flow Information
  Cash Paid During the Year for Interest
     (Net of Amounts Capitalized of $214, $206 and $249,
       Respectively)........................................  $  45,004   $  48,197   $ 44,199
                                                              =========   =========   ========
</Table>

        The accompanying notes are an integral part of these statements.

                                       113
<PAGE>

                GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND MANAGEMENT

     Great Lakes Gas Transmission Limited Partnership (Partnership) is a
Delaware limited partnership which owns and operates an interstate natural gas
pipeline system. The Partnership transports natural gas for delivery to
customers in the midwestern and northeastern United States and eastern Canada.
Partnership ownership percentages are recalculated each year to reflect
distributions and contributions. The partners, their parent companies, and
partnership ownership percentages are as follows:

<Table>
<Caption>
                                                               OWNERSHIP %
                                                              -------------
PARTNER (PARENT COMPANY)                                      2002    2001
------------------------                                      -----   -----
<S>                                                           <C>     <C>
General Partners:
  El Paso Great Lakes, Inc. (El Paso Corporation)...........  45.74   45.40
  TransCanada GL, Inc. (TransCanada PipeLines Ltd.).........  45.74   45.40
Limited Partner:
  Great Lakes Gas Transmission Company (TransCanada
     PipeLines Ltd. and El Paso Corporation)................   8.52    9.20
</Table>

     The El Paso Corporation (El Paso) interests were formerly owned by The
Coastal Corporation (Coastal), which merged into a subsidiary of El Paso on
January 29, 2001.

     The day-to-day operation of Partnership activities is the responsibility of
Great Lakes Gas Transmissions Company (Company), which is reimbursed for its
employee salaries, benefits and other expenses, pursuant to the Partnership's
Operating Agreement with the Company.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

  Principles of Consolidation and Basis of Presentation

     The consolidated financial statements include the accounts of the
Partnership and GLGT Aviation Company, a wholly owned subsidiary. GLGT Aviation
Company owns a transport aircraft used principally for pipeline operations.
Intercompany amounts have been eliminated.

     For purposes of reporting cash flows, the Partnership considers all liquid
investments with original maturities of three months or less to be cash
equivalents.

     The Partnership recognizes revenues from natural gas transportation in the
period the service is provided.

     Management of the Partnership has made estimates and assumptions relating
to the reporting of assets and liabilities and the disclosure of contingent
assets and liabilities to prepare these financial statements in conformity with
accounting principles generally accepted in the United States of America. Actual
results could differ from those estimates.

  Regulation

     The Partnership is subject to the rules, regulations and accounting
procedures of the Federal Energy Regulatory Commission (FERC). The Partnership's
accounting policies reflect the effects of the ratemaking process in accordance
with Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for
the Effects of Certain Types of Regulation. Regulatory assets and liabilities
have been established and represent probable future revenue or expense which
will be recovered from or refunded to customers. The regulatory assets and
liabilities are primarily related to prior changes in federal income tax rates.

                                       114
<PAGE>

  Accounts Receivable

     Accounts Receivable are reported net of an allowance for doubtful accounts
of $2,095,000 and $1,200,000 for 2002 and 2001, respectively. Late fees are
recognized as income when earned.

  Gas Utility Plant and Depreciation

     Gas utility plant is stated at cost and includes certain administrative and
general expenses, plus an allowance for funds used during construction. The cost
of plant retired is charged to accumulated depreciation. Depreciation of gas
utility plant is computed using the straight-line method. The Partnership's
principal operating assets are depreciated at an annual rate of 2.75% for both
2002 and 2001 and 3.00% for 2000.

     The allowance for funds used during construction represents the debt and
equity costs of capital funds applicable to utility plant under construction,
calculated in accordance with a uniform formula prescribed by the FERC. The rate
used for both 2002 and 2001 was 10.36% and for 2000 was 10.95%.

  Income Taxes

     The Partnership's tariff includes an allowance for income taxes which the
FERC requires the Partnership to record as if it were a corporation. The
provisions for current and deferred income tax expense are recorded without
regard to whether each partner can utilize its share of the Partnership's tax
deductions. Income taxes are deducted in the Consolidated Statements of Income
and the current portion of income taxes is returned to partners' capital.
Recorded current income taxes are distributed to partners based on their
ownership percentages.

     Amounts equivalent to deferred tax assets and liabilities are recognized
for the future tax consequences attributable to differences between the
financial statement carrying amounts of assets and liabilities and their
respective tax bases at currently enacted income tax rates.

3. AFFILIATED COMPANY TRANSACTIONS

     Affiliated company amounts included in the Partnership's consolidated
financial statements, not otherwise disclosed, are as follows:

<Table>
<Caption>
                                                         2002       2001       2000
                                                       --------   --------   --------
                                                               (IN THOUSANDS)
<S>                                                    <C>        <C>        <C>
Accounts receivable..................................  $ 15,999   $ 15,936   $ 17,447
Transportation revenues:
  TransCanada PipeLines Ltd. and affiliates..........   163,442    176,818    185,912
  El Paso Corporation and affiliates.................    24,875     25,716         --
  The Coastal Corporation affiliates.................        --         --     28,981
Interest income......................................        --         --      3,664
</Table>

     The majority of affiliated transportation revenues are provided under fixed
price contracts with remaining terms ranging from 2 months to 10 years.

     The Partnership reimburses the Company for salaries, benefits and other
incurred expenses. Benefits include pension, thrift plan, and other
post-retirement benefits. Operating expenses charged by the Company in 2002,
2001 and 2000 were $17,888,000, $13,671,000 and $21,147,000, respectively.

     The Company accounts for pension benefits on an accrual basis. Effective
with the merger of The Coastal Corporation and El Paso Corporation in 2001, the
former pension plan was merged into the El Paso cash balance pension plan. The
annual net pension credit was $5,400,000, $8,500,000 and $5,000,000 in 2002,
2001 and 2000, respectively.

     The Company makes contributions for eligible employees of the Company to a
voluntary defined contribution plan sponsored by one of the parent companies.
The Company's contributions, which are based

                                       115
<PAGE>

on matching employee contributions, amounted to $770,000, $832,000 and $980,000
in 2002, 2001 and 2000, respectively.

     The Company accounts for other post-retirement benefits on an accrual
basis. The annual expense was $236,000, $215,000 and $556,000 for 2002, 2001 and
2000, respectively. In addition, curtailment costs of approximately $695,000
were recorded in 2001 related to the conversion to the El Paso Corporation
benefit plans, which changed future benefits for eligible employees.

4. REGULATORY MATTERS

     On October 26, 2000, the FERC issued an order approving the Partnership's
filing of a Joint Stipulation and Agreement Regarding Rates which was
subsequently reaffirmed on February 8, 2001, by its order denying rehearing. The
settlement continues the Partnership's existing rates until October 31, 2005,
and provides a decrease in the Partnership's depreciation rate from 3.00% to
2.75% for transmission plant effective January 1, 2001.

5. DEBT

     Senior Notes, unsecured, interest due semiannually, principal due as
follows:

<Table>
<Caption>
                                                                2002       2001
                                                              --------   --------
                                                                (IN THOUSANDS)
<S>                                                           <C>        <C>
  9.81% series, due 2002....................................  $     --   $ 12,750
  9.35% series, due 2002 to 2005............................    31,500     56,000
  8.74% series, due 2002 to 2011............................    90,000    100,000
  9.09% series, due 2012 to 2021............................   100,000    100,000
  6.73% series, due 2009 to 2018............................    90,000     90,000
  6.95% series, due 2019 to 2028............................   110,000    110,000
  8.08% series, due 2021 to 2030............................   100,000    100,000
                                                              --------   --------
                                                               521,500    568,750
Less current maturities.....................................    24,000     36,500
                                                              --------   --------
Total long term debt less current maturities................  $497,500   $532,250
                                                              ========   ========
</Table>

     The aggregate estimated fair value of long term debt was $628,000,000 and
$607,000,000 for 2002 and 2001, respectively. The fair value is determined using
discounted cash flows based on the Partnership's estimated current interest
rates for similar debt.

     The aggregate annual required repayments of Senior Notes for each of the
five years 2003 through 2007 are $24,000,000, $24,000,000, $13,500,000,
$10,000,000 and $10,000,000, respectively.

     Under the most restrictive covenants in the Senior Note Agreements,
approximately $281,000,000 of partners' capital is restricted as to
distributions as of December 31, 2002.

                                       116
<PAGE>

6. INCOME TAXES PAYABLE BY PARTNERS

     Income tax expense for the years ended December 31, 2002, 2001 and 2000
consists of:

<Table>
<Caption>
                                                           2002      2001      2000
                                                          -------   -------   -------
                                                                (IN THOUSANDS)
<S>                                                       <C>       <C>       <C>
Current
  Federal...............................................  $26,612   $22,366   $23,496
  State.................................................    1,189     1,012     1,052
                                                          -------   -------   -------
                                                           27,801    23,378    24,548
                                                          -------   -------   -------
Deferred
  Federal...............................................   16,808    15,835    14,306
  State.................................................      791       737       664
                                                          -------   -------   -------
                                                           17,599    16,572    14,970
                                                          -------   -------   -------
                                                          $45,400   $39,950   $39,518
                                                          =======   =======   =======
</Table>

     Income tax expense differs from the statutory rate of 35% due to the
amortization of excess deferred taxes along with the effects of state and local
taxes. The Partnership is required to amortize excess deferred taxes which had
previously been accumulated at tax rates in excess of current statutory rates.
Such amortization reduced income tax expense by $900,000 for 2002, 2001 and
2000. As of December 31, 2002, the remaining unamortized balance is $1,475,000.

     Amounts equivalent to deferred income taxes are principally comprised of
temporary differences associated with excess tax depreciation on utility plant.
As of December 31, 2002 and 2001, no valuation allowance is required. The
deferred tax assets and deferred tax liabilities as of December 31, 2002 and
2001 are as follows:

<Table>
<Caption>
                                                                2002        2001
                                                              ---------   ---------
                                                                 (IN THOUSANDS)
<S>                                                           <C>         <C>
Deferred tax assets.........................................  $   5,110   $   4,868
Deferred tax liabilities -- utility plant...................   (214,526)   (197,927)
Deferred tax liabilities -- other...........................    (14,882)    (12,998)
                                                              ---------   ---------
Net deferred tax liability..................................  $(224,298)  $(206,057)
                                                              =========   =========
</Table>

7. USE TAX REFUNDS

     In the first quarter of 2002, Great Lakes received a favorable decision
from the Minnesota Supreme Court on use tax litigation and has collected refunds
and related interest on litigated claims and pending claims for 1994 to 2001.
The total amount received was $13.7 million. The refunds are reflected in
Property and Other Taxes ($10.9 million) and the interest included in Other, Net
($2.8 million).

                                       117
<PAGE>

                              EL PASO CGP COMPANY

                                  EXHIBIT LIST

                               DECEMBER 31, 2002

     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 asterisk;
all exhibits not so designated are incorporated herein by reference to a prior
filing as indicated. Exhibits designated with a "+" constitute a management
contract or compensatory plan or arrangement required to be filed as an exhibit
to this report pursuant to Item 14(c) of Form 10-K.

<Table>
<Caption>
EXHIBIT NO.                           DESCRIPTION
-----------                           -----------
<S>           <C>
     3.A      Amended and Restated Certificate of Incorporation dated
              January 31, 2001 (Exhibit 3.A to our 2000 Form 10-K).

    *3.B      By-laws dated June 24, 2002.

    10.A      $1,000,000,000 Amended and Restated 3-Year Revolving Credit
              and Competitive Advance Facility Agreement dated June 27,
              2002, by and among El Paso EPNG, TGP, El Paso CGP, the
              several banks and other financial institutions from time to
              time parties thereto, and JPMorgan Chase Bank, as
              Administrative Agent, CAF Advance Agent and Issuing Bank,
              Citibank, N.A. and ABN Amro Bank N.V., as Co-Documentation
              Agents, and Bank of America, N.A., as Syndication Agent
              (Exhibit 10.B to our 2002 Second Quarter Form 10-Q).

   *99.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. A signed original of this
              written statement required by sec. 906 has been provided to
              El Paso CGP Company and will be retained by El Paso CGP
              Company and furnished to the Securities and Exchange
              Commission or its staff upon request.

   *99.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. A signed original of this
              written statement required by sec. 906 has been provided to
              El Paso CGP Company and will be retained by El Paso CGP
              Company and furnished to the Securities and Exchange
              Commission or its staff upon request.
</TABLE>

     (b) REPORTS ON FORM 8-K

        January 28, 2003     Announced the sale of our petroleum terminals and
                             tug & barge operations and provided pro-forma
                             financials of El Paso CGP.


                                       118
<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 31st day of March 2003.

                                        EL PASO CGP COMPANY
                                            Registrant

                                        By:     /s/ RONALD L. KUEHN, JR.
                                           -------------------------------------
                                                   Ronald L. Kuehn, Jr.
                                                 Chairman of the Board 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
                     ---------                                     -----                     ----
<C>                                                  <S>                                <C>

           By: /s/ RONALD L. KUEHN, JR.              Chairman of the Board, Chief       March 31, 2003
  ----------------------------------------------       Executive Officer and Director
              (Ronald L. Kuehn, Jr.)                   (Principal Executive Officer)

              By: /s/ H. BRENT AUSTIN                President, Chief Operating         March 31, 2003
  ----------------------------------------------       Officer and Director
                 (H. Brent Austin)

              By: /s/ D. DWIGHT SCOTT                Executive Vice President and       March 31, 2003
  ----------------------------------------------       Chief Financial Officer and
                 (D. Dwight Scott)                     Director (Principal Financial
                                                       Officer)

             By: /s/ JEFFREY I. BEASON               Senior Vice President and          March 31, 2003
  ----------------------------------------------       Controller
                (Jeffrey I. Beason)                    (Principal Accounting Officer)
</Table>

                                       119
<PAGE>

                                 CERTIFICATION

I, Ronald L. Kuehn, Jr., certify that:

     1. I have reviewed this annual report on Form 10-K of El Paso CGP Company;

     2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

     3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

     4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

          a) designed such disclosure controls and procedures to ensure that
     material information relating to the registrant, including its consolidated
     subsidiaries, is made known to us by others within those entities,
     particularly during the period in which this annual report is being
     prepared;

          b) evaluated the effectiveness of the registrant's disclosure controls
     and procedures as of a date within 90 days prior to the filing date of this
     annual report (the "Evaluation Date"); and

          c) presented in this annual report our conclusions about the
     effectiveness of the disclosure controls and procedures based on our
     evaluation as of the Evaluation Date;

     5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):

          a) all significant deficiencies in the design or operation of internal
     controls which could adversely affect the registrant's ability to record,
     process, summarize and report financial data and have identified for the
     registrant's auditors any material weaknesses in internal controls; and

          b) any fraud, whether or not material, that involves management or
     other employees who have a significant role in the registrant's internal
     controls; and

     6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

                                               /s/ RONALD L. KUEHN, JR.
                                          --------------------------------------
                                                   Ronald L. Kuehn, Jr.
                                                Chairman of the Board and
                                                 Chief Executive Officer
                                              (Principal Executive Officer)
                                                   El Paso CGP Company
Date: March 31, 2003

                                       120
<PAGE>

                                 CERTIFICATION

I, D. Dwight Scott, certify that:

     1. I have reviewed this annual report on Form 10-K of El Paso CGP Company;

     2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

     3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

     4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

          a) designed such disclosure controls and procedures to ensure that
     material information relating to the registrant, including its consolidated
     subsidiaries, is made known to us by others within those entities,
     particularly during the period in which this annual report is being
     prepared;

          b) evaluated the effectiveness of the registrant's disclosure controls
     and procedures as of a date within 90 days prior to the filing date of this
     annual report (the "Evaluation Date"); and

          c) presented in this annual report our conclusions about the
     effectiveness of the disclosure controls and procedures based on our
     evaluation as of the Evaluation Date;

     5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):

          a) all significant deficiencies in the design or operation of internal
     controls which could adversely affect the registrant's ability to record,
     process, summarize and report financial data and have identified for the
     registrant's auditors any material weaknesses in internal controls; and

          b) any fraud, whether or not material, that involves management or
     other employees who have a significant role in the registrant's internal
     controls; and

     6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

                                                  /s/ D. DWIGHT SCOTT
                                          --------------------------------------
                                                     D. Dwight Scott
                                               Executive Vice President and
                                                 Chief Financial Officer
                                              (Principal Financial Officer)
                                                   El Paso CGP Company
Date: March 31, 2003

                                       121
<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 asterisk;
all exhibits not so designated are incorporated herein by reference to a prior
filing as indicated. Exhibits designated with a "+" constitute a management
contract or compensatory plan or arrangement required to be filed as an exhibit
to this report pursuant to Item 14(c) of Form 10-K.

<Table>
<Caption>
EXHIBIT NO.                           DESCRIPTION
-----------                           -----------
<S>           <C>
     3.A      Amended and Restated Certificate of Incorporation dated
              January 31, 2001 (Exhibit 3.A to our 2000 Form 10-K).
    *3.B      By-laws dated June 24, 2002.
    10.A      $1,000,000,000 Amended and Restated 3-Year Revolving Credit
              and Competitive Advance Facility Agreement dated June 27,
              2002, by and among El Paso EPNG, TGP, El Paso CGP, the
              several banks and other financial institutions from time to
              time parties thereto, and JPMorgan Chase Bank, as
              Administrative Agent, CAF Advance Agent and Issuing Bank,
              Citibank, N.A. and ABN Amro Bank N.V., as Co-Documentation
              Agents, and Bank of America, N.A., as Syndication Agent
              (Exhibit 10.B to our 2002 Second Quarter Form 10-Q).
   *99.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. A signed original of this
              written statement required by sec. 906 has been provided to
              El Paso CGP Company and will be retained by El Paso CGP
              Company and furnished to the Securities and Exchange
              Commission or its staff upon request.
   *99.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. A signed original of this
              written statement required by sec. 906 has been provided to
              El Paso CGP Company and will be retained by El Paso CGP
              Company and furnished to the Securities and Exchange
              Commission or its staff upon request.
</Table>