<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, 2001

                                       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 1-9864

                         EL PASO TENNESSEE PIPELINE CO.
             (Exact name of registrant as specified in its charter)

<Table>
<S>                                                 <C>
                     DELAWARE                                           76-0233548
         (State or other jurisdiction of                             (I.R.S. Employer
          incorporation or organization)                           Identification No.)

                 EL PASO BUILDING
              1001 LOUISIANA STREET
                  HOUSTON, TEXAS                                          77002
     (Address of principal executive offices)                           (Zip Code)
</Table>

       REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (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 1/4% Cumulative Preferred Stock, Series A.................   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]

     STATE THE AGGREGATE MARKET VALUE OF THE VOTING STOCK HELD BY NON-AFFILIATES
OF THE REGISTRANT.

     Aggregate market value shall be computed by reference to the price at which
the stock was sold, or the average bid and asked prices of such stock, as of the
specified date within 60 days prior to the date of filing.

<Table>
<Caption>
                                                                  MARKET VALUE
         CLASS OF VOTING STOCK AND NUMBER OF SHARES                   HELD
          HELD BY NON-AFFILIATES AT MARCH 20, 2002              BY NON-AFFILIATES
          ----------------------------------------              -----------------
<S>                                                             <C>
8 1/4% Cumulative Preferred Stock, Series A, 6,000,000
shares                                                            $302,160,000*
</Table>

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

*  Based upon the closing price on the Composite Tape for the 8 1/4% Cumulative
   Preferred Stock, Series A, on March 20, 2002.

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

     Common Stock, par value $0.01 per share. Shares outstanding on March 20,
2002: 1,971

                      DOCUMENTS INCORPORATED BY REFERENCE

     List hereunder the following documents if incorporated by reference and the
part of the Form 10-K (e.g., Part I, Part II, etc.) into which the document is
incorporated: our definitive Proxy Statement for the 2002 Annual Meeting of
Stockholders, to be filed not later than 120 days after the end of the fiscal
year covered by this report, is incorporated by reference into Part III.

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

                         EL PASO TENNESSEE PIPELINE CO.

                               TABLE OF CONTENTS

<Table>
<Caption>
                                     CAPTION                             PAGE
                                     -------                             ----
<S>        <C>                                                           <C>
                                      PART I
Item 1.    Business....................................................    1
Item 2.    Properties..................................................   10
Item 3.    Legal Proceedings...........................................   10
Item 4.    Submission of Matters to a Vote of Security Holders.........   10

                                     PART II
Item 5.    Market for Registrant's Common Equity and Related
             Stockholder Matters.......................................   11
Item 6.    Selected Financial Data.....................................   11
Item 7.    Management's Discussion and Analysis of Financial Condition
             and Results of Operations.................................   12
           Cautionary Statement for Purposes of the "Safe Harbor"
             Provisions of the Private Securities Litigation Reform Act
             of 1995...................................................   28
Item 7A.   Quantitative and Qualitative Disclosures About Market
             Risk......................................................   29
Item 8.    Financial Statements and Supplementary Data.................   33
Item 9.    Changes in and Disagreements with Accountants on Accounting
             and Financial Disclosure..................................   71

                                     PART III
Item 10.   Directors and Executive Officers of the Registrant..........   71
Item 11.   Executive Compensation......................................   71
Item 12.   Security Ownership of Beneficial Owners and Management......   71
Item 13.   Certain Relationships and Related Transactions..............   71

                                     PART IV
Item 14.   Exhibits, Financial Statement Schedules and Reports on Form
             8-K.......................................................   72
           Signatures..................................................   74
</Table>

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

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

<Table>
<S>      <C>
/d       = per day
Bbl      = barrels
BBtu     = billion British thermal units
BBtue    = billion British thermal unit
           equivalents
Bcf      = billion cubic feet
MBbls    = thousand barrels
MMBbls   = million barrels
MMBtu    = million British thermal units
Mcf      = thousand cubic feet
Mcfe     = thousand cubic feet of gas equivalents
MMcf     = million cubic feet
MMcfe    = million cubic feet of gas equivalents
Mgal     = thousand gallons
MTons    = thousand tons
MWh      = megawatt hours
MMWh     = thousand megawatt hours
TBtu     = trillion British thermal units
</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 is equal to six Mcf of natural
gas. Also, when we refer to cubic feet measurements, all measurements are at
14.73 pounds per square inch.

    When we refer to "we", "us", "our", "ours", or "El Paso Tennessee", we are
describing El Paso Tennessee Pipeline Co. and/or our subsidiaries.

                                        i
<PAGE>

                                     PART I

ITEM 1. BUSINESS

                                    GENERAL

     Prior to 1996, we operated as Tenneco Inc., an entity with operations in
the automotive, energy, packaging and shipbuilding businesses. During the latter
part of 1996, Tenneco distributed to its shareholders all of its businesses
except for its energy business and some of its corporate and discontinued
operations. In December 1996, El Paso Corporation acquired these remaining
business operations and renamed us El Paso Tennessee Pipeline Co. At December
31, 2001, El Paso owned 100 percent of our common stock and greater than 80
percent of our equity value. The remaining equity value consists of
approximately $300 million of outstanding preferred stock that is traded on the
New York Stock Exchange.

     Our principal operations include:

      - natural gas transportation, gathering, processing and storage;

      - energy and energy-related commodities and products marketing;

      - power generation; and

      - energy infrastructure facility development and operation.

                                    SEGMENTS

     Our operations are segregated into three primary business segments:
Pipelines, Merchant Energy and Field Services. 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. For information relating to operating revenues, operating
income, earnings before interest expense and income taxes (EBIT) and
identifiable assets by segment, you should see Part II, Item 8, Financial
Statements and Supplementary Data, Note 13, which is incorporated herein by
reference.

     Our Pipelines segment owns or has interests in approximately 16,400 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
three of the largest consuming regions in the U.S.: the Gulf Coast, the
Northeast and the Midwest. Our natural gas transmission operations are comprised
of the Tennessee Gas Pipeline system, our wholly owned interstate pipeline
system, as well as interests in the Portland Natural Gas Transmission system and
the Bear Creek storage facility. Our international pipeline operations include
our interests in three major operating natural gas transmission systems in
Australia.

     Our Merchant Energy segment is involved in a broad range of energy-related
activities including asset ownership, customer origination, marketing and
trading and financial services. We buy, sell and trade natural gas, power and
other energy commodities in the U.S. and internationally. We are also a
significant owner of electric generating capacity and own or have interests in
77 facilities in 16 countries. Our financial services businesses manage
investments in the North American energy industry. Most recently, Merchant
Energy has announced its expansion into the liquefied natural gas (LNG)
business.

     Our Field Services segment provides natural gas gathering, products
extraction, fractionation, dehydration, purification, compression and intrastate
transmission services. These services include gathering natural gas from more
than 12,000 natural gas wells with over 17,000 miles of natural gas gathering
and natural gas liquids pipelines, and 16 natural gas processing, treating and
fractionation facilities located in some of the most active production areas in
the U.S., including the San Juan Basin, east and south Texas, Louisiana and the
Gulf of Mexico. We conduct our intrastate transmission operations through
interests in five intrastate systems, which serve a majority of the metropolitan
areas and industrial load centers in Texas as well as markets in Louisiana.

                                        1
<PAGE>

                               PIPELINES SEGMENT

     Our Pipelines segment provides natural gas transmission services in the
U.S. and internationally. We conduct our activities through one wholly owned and
four partially owned interstate transmission systems along with a natural gas
storage facility. The table below details our wholly and partially owned
interstate pipeline systems:
<Table>
<Caption>
                                                                                                              AVERAGE
                                                                                                           THROUGHPUT(1)
      PIPELINE                        SUPPLY AND                  OWNERSHIP   MILES OF     DESIGN      ---------------------
       SYSTEM                        MARKET REGION                INTEREST    PIPELINE   CAPACITY(1)   2001    2000    1999
      --------                       -------------                ---------   --------   -----------   -----   -----   -----
                                                                  (PERCENT)               (MMCF/D)           (BBTU/D)
<S>                    <C>                                        <C>         <C>        <C>           <C>     <C>     <C>
Tennessee Gas          Extends from Louisiana, the Gulf of           100       14,200       6,194      4,405   4,354   4,253
 Pipeline (TGP)        Mexico and south Texas to the northeast
                       section of the U.S., including New York
                       City and Boston.

Dampier-to-Bunbury     Extends from Dampier to Bunbury in             33          925         570        555     523     485
 pipeline system       western Australia.

Moomba-to-Adelaide     Extends from Moomba to Adelaide in             33          488         383        261     231     220
 pipeline system       southern Australia.

Ballera-to-Wallumbilla Extends from Ballera to Wallumbilla in         33          470         115         71      71      59
 pipeline system       southwestern Queensland, Australia.

Portland Natural Gas   Extends from the Canadian border near          30(2)       300         214        123     110      61
 Transmission          Pittsburg, New Hampshire to Dracut,
                       Massachusetts.

<Caption>

      PIPELINE         STORAGE
       SYSTEM          CAPACITY
      --------         --------
                        (BCF)
<S>                    <C>
Tennessee Gas             95(3)
 Pipeline (TGP)

Dampier-to-Bunbury        --
 pipeline system

Moomba-to-Adelaide        --
 pipeline system

Ballera-to-Wallumbill     --
 pipeline system

Portland Natural Gas      --
 Transmission
</Table>

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

(1) Volumes represent the systems' total design capacity and average throughput
    and are not adjusted for our ownership interest.
(2) Our ownership interest increased from 19 percent to 30 percent effective
    June 2001.
(3) 5 Bcf of capacity is contracted from ANR Pipeline Company, our affiliate.

     We own a 50 percent interest in Bear Creek Storage Company, which owns and
operates an underground natural gas storage facility located in Louisiana.
Southern Natural Gas Company, our affiliate, owns the remaining 50 percent
interest. The facility has a capacity of 50 Bcf of base gas and 58 Bcf of
working storage. Bear Creek's working storage capacity is committed equally to
the Southern Natural Gas system and our TGP system under long-term contracts.

     The following transmission system expansion projects have been approved by
the Federal Energy Regulatory Commission (FERC):

<Table>
<Caption>
                                                                                                   ANTICIPATED
        PROJECT         CAPACITY                           DESCRIPTION                           COMPLETION DATE
        -------         --------                           -----------                           ---------------
                        (MMCF/D)
  <C>                   <C>        <S>                                                           <C>
      Stagecoach          100      Connects the Stagecoach Storage Field in New York to our        Completed
                                   mainline in Pennsylvania and expands our 300 Line to provide  February 2002
                                   firm transportation service to interconnect with New Jersey
                                   Natural in Passaic, New Jersey.

      FPL project          90      Installation of compression and a meter to supply Florida     September 2002
                                   Power and Light's facility in Rhode Island.
</Table>

  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 operates under separate FERC approved tariffs that
establish rates, terms and conditions under which we provide services to our
customers. Generally, the FERC's authority extends to:

     - transportation and storage of natural gas, rates and charges;

     - certification and construction of new facilities;

     - extension or abandonment of services and facilities;

     - maintenance of accounts and records;

     - relationships between pipeline and marketing affiliates;

                                        2
<PAGE>

     - depreciation and amortization policies;

     - acquisition and disposition of facilities; and

     - initiation and discontinuation of services.

     Our wholly and partially owned domestic pipelines and storage facility have
tariffs established through filings with the FERC that have a variety of terms
and conditions, each of which affects our operations and our ability to recover
fees for the services we provide. Generally, changes to these fees or terms of
service can only be implemented upon approval by the FERC. In Australia, various
regional and national agencies regulate the tariffs, rates and operating
activities of natural gas pipelines.

     Our interstate pipeline systems are also subject to the Natural Gas
Pipeline Safety Act of 1968, which establishes pipeline safety requirements, the
National Environmental Policy Act and other environmental legislation. Each has
a continuing program of inspection designed to keep all of our facilities in
compliance with pollution control and pipeline safety requirements. We believe
that our systems are in compliance with the applicable requirements.

     We are also subject to regulation with respect to safety requirements in
the design, construction, operation and maintenance of our interstate natural
gas transmission systems and storage facility by the U.S. Department of
Transportation. Operations on U.S. government land are regulated by the U.S.
Department of the Interior.

     For a discussion of significant rate and regulatory matters, see Part II,
Item 8, Financial Statements and Supplementary Data, Note 10.

 Markets and Competition

     Our interstate transmission systems face varying degrees of competition
from other pipelines, as well as alternative energy sources, such as
electricity, hydroelectric power, coal and fuel oil. Also, the potential
consequences of proposed and ongoing restructuring and deregulation of the
electric power industry are currently unclear. Restructuring and deregulation
may benefit the natural gas industry by creating more demand for natural gas
turbine generated electric power, or it may hamper demand by allowing a more
effective use of surplus electric capacity through increased wheeling as a
result of open access.

     Our TGP system has approximately 430 firm and interruptible customers,
including natural gas producers, marketers, end-users and other natural gas
transmission, distribution and electric generation companies. TGP has
approximately 500 firm transportation contracts with remaining terms that extend
from 1 month to 10 years and with an average remaining contract term of 5 years.
Approximately 95 percent of our total capacity is subscribed under firm
transportation agreements.

     TGP faces strong competition in the Northeast, Appalachian, Midwest and
Southeast market areas. It competes with interstate pipelines for deliveries to
multiple-connection customers. Natural gas delivered on the TGP system competes
with alternate fuels, principally oil and coal. TGP also competes with pipelines
and local distribution companies to connect new loads. In addition, TGP competes
with pipelines and gathering systems for connection to new supply sources in
Texas, the Gulf of Mexico and at the Canadian border.

     Our ability to extend existing contracts or re-market expiring capacity
with our customers is based on a variety of factors, including competitive
alternatives, the regulatory environment at the local, state and federal levels
and market supply and demand factors at the relevant extension or expiration
dates. While we make every attempt to re-negotiate contract terms at
fully-subscribed quantities and at maximum rates allowed under our tariffs, we
must, at times, discount our rates to remain competitive.

                            MERCHANT ENERGY SEGMENT

     Our Merchant Energy segment is involved in a broad range of activities in
the energy marketplace, including asset ownership, customer origination,
marketing and trading and financial services.

                                        3
<PAGE>

ASSET OWNERSHIP

     Merchant Energy's Asset Ownership activities include ownership interests in
domestic and international power generation and an emerging LNG business.

     Power Generation.  Our commercial focus in the power generation business is
to either develop projects in which new long-term power purchase agreements
allow for an acceptable return on capital, or to acquire projects with existing
attractive power purchase agreements. Under this strategy, we have become a
significant U.S.-based independent power generator and currently own or have
interests in 77 power plants in 16 countries. These plants represent 17,867
gross megawatts of generating capacity, 88 percent of which is sold under power
purchase or tolling agreements with terms in excess of five years. Of these
facilities, 66 percent are natural gas fired, 13 percent are geothermal and 21
percent are a combination of coal, natural gas liquids and hydroelectric.

     A significant portion of our domestic activity is conducted within an
unconsolidated affiliate, Chaparral Investors, L.L.C. Chaparral's primary
strategy is to acquire power plants with above-market power contracts and
restructure these contracts by offering a lower power sales cost to the plants'
customers, which are typically electric utilities. Through Chaparral (an entity
that we have also referred to in our public disclosures as Electron), we have
invested in 39 U.S. power generation facilities with a total generating capacity
of approximately 5,900 gross megawatts. We serve as the manager of Chaparral
under a management agreement that expires in 2006, and are paid an annual
performance-based fee for the services we perform under this agreement. Our
activities as manager of Chaparral include:

     - management of the operations and commercial activities of the facilities;

     - project-level contract restructurings and monetizations;

     - project financings, sales and acquisitions;

     - identification, evaluation, negotiation and consummation of new
       investments in energy assets; and

     - daily administration activities of accounting, tax, legal and treasury
       functions.

     Internationally, our focus is on building energy infrastructure in
developed economies, and to a lesser degree in selected emerging markets. Our
primary areas of focus include Brazil, Europe, Korea and Japan. We principally
conduct our Brazilian development activities within an unconsolidated affiliate
that we refer to as Gemstone. Through our ownership interest in Gemstone, we
have invested in five Brazilian power generation facilities with a total
generating capacity of approximately 2,156 gross megawatts. We serve as the
manager of Gemstone under a management agreement that expires in 2004. Our
activities as manager of Gemstone are similar to those described above for
Chaparral.

                                        4
<PAGE>

     Detailed below are our power generation projects, by region, that are
either operational or in various stages of construction:

<Table>
<Caption>
                                                            NUMBER OF      GROSS      NET(1)
REGION                    PROJECT STATUS                    FACILITIES   MEGAWATTS   MEGAWATTS
------                    --------------                    ----------   ---------   ---------
<S>                       <C>                               <C>          <C>         <C>
United States
  East Coast              Operational....................       18         2,917       1,989
                          Under Construction.............        3         1,390       1,361
  Central                 Operational....................        5           475         433
                          Under Construction.............        2           600         345
  West Coast              Operational....................       26         1,694         665
South America             Operational....................        8         4,984       1,976
                          Under Construction.............        1           470         282
Asia                      Operational....................        8         2,935       1,406
                          Under Construction.............        1           762         189
Europe                    Operational....................        4           940         940
Mexico                    Operational....................        1           700         700
                                                                --        ------      ------
          Total..........................................       77        17,867      10,286
                                                                ==        ======      ======
</Table>

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

(1) Net Megawatts represent our net ownership in the facilities.

     LNG.  Our LNG business contracts for LNG terminalling and regasification
capacity, coordinates short and long-term LNG supply deliveries and is
developing an international LNG supply, marketing and infrastructure business.
As of December 31, 2001, our LNG business had contracted for 284 Bcf per year of
LNG regasification capacity at three locations along the Eastern and Gulf of
Mexico coastal regions of the U.S. as follows:

<Table>
<Caption>
                                                      CONTRACTED     CONTRACTED      EXPIRATION
FACILITY                       LOCATION                CAPACITY    IN SERVICE DATE      DATE
--------                       --------               ----------   ---------------   ----------
                                                       (MMCF/D)
<S>               <C>                                 <C>          <C>               <C>
Elba Island       Georgia...........................      446           2001            2023
Cove Point        Maryland..........................      250           2002            2022
Lake Charles      Louisiana.........................       82           2003            2007
</Table>

     We have also contracted for 105 Bcf per year of long-term supplies of LNG
at market sensitive prices, which will be delivered from the Caribbean beginning
in 2002. In addition, we have contracted to lease four LNG tankers to transport
LNG from supply areas to domestic and international market centers. These ships
are currently being constructed by third parties with the first ship scheduled
for delivery in 2003.

     Operations. Merchant Energy has established an Operations group to manage
the daily operations of Merchant Energy's worldwide assets. This group operates
18 generating facilities in the U.S. and four facilities in two foreign
countries.

CUSTOMER ORIGINATION, MARKETING AND TRADING

     Our Merchant Energy segment is one of the largest energy marketers in North
America, and manages a large network of energy assets, both owned and under
contract, which are used in the delivery of natural gas and power. Merchant
Energy's customer origination activities provide short and long-term supplies of
energy commodities to a broad range of wholesale customers worldwide. These
activities provide customers with alternatives to meet their energy supply needs
and manage their associated energy risks through Merchant Energy's: (i)
knowledge of the marketplace; (ii) network of delivery infrastructure; (iii)
supply aggregation and transportation management capabilities; and (iv)
valuation and integrated price risk management skills. Merchant Energy's
marketing and trading groups trade natural gas, power, other energy commodities
and related financial instruments in North America and Europe and provide
pricing and valuation analysis for the

                                        5
<PAGE>

entire segment. These groups manage the inherent risk of Merchant Energy's asset
and trading portfolios using value-at-risk limits approved by the Audit
Committee of El Paso's Board of Directors and attempt to optimize the value of
the segment's asset portfolio.

     During 2001, Merchant Energy's traded volumes increased across all
commodity groups. Detailed below is the marketed and traded energy commodity
volumes for each the three years ended December 31:

<Table>
<Caption>
                                                           2001      2000      1999
                                                          -------   -------   -------
<S>                                                       <C>       <C>       <C>
Volumes
  Physical
     Natural gas (BBtue/d)..............................    8,938     6,899     6,713
     Power (MMWh).......................................  220,668   116,749    79,361
     Other energy commodities (MBbls)...................   19,444     7,772     4,990
  Financial settlements (BBtue/d).......................  143,096    98,664    68,678
</Table>

FINANCIAL SERVICES

     Our Financial Services group provides institutional and retail funds
management and makes capital investments for Merchant Energy. It conducts these
activities primarily through two subsidiaries, EnCap Investments, L.L.C. and
Enerplus Global Investment Management, Inc.

     EnCap is an institutional funds management firm specializing in financing
independent oil and natural gas producers. EnCap manages four separate
institutional oil and natural gas investment funds in the U.S. and serves as
investment advisor to Energy Capital Investment Company PLC, a publicly traded
investment company in the United Kingdom. Enerplus is an institutional and
retail funds management firm in Canada. EnCap and Enerplus manage funds that had
a combined market value of approximately $1.4 billion at December 31, 2001.

  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. Its cogeneration power production
activities are regulated by the FERC under the Public Utility Regulatory
Policies Act with respect to rates, procurement and provision of services and
operating standards. Its power generation activities are also subject to federal
and state environmental regulations, including the U.S. Environmental Protection
Agency (EPA) regulations. We believe that our operations are in compliance with
the applicable requirements.

     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
compliance with all environmental laws and regulations in the applicable foreign
jurisdictions.

  Markets and Competition

     Merchant Energy maintains a diverse supplier and customer base. During
2001, its activities served over 1,000 suppliers and over 900 customers around
the world.

     Merchant Energy's trading, marketing and energy infrastructure development
businesses operate in a highly competitive environment. Its primary competitors
include:

     - affiliates of major oil and natural gas producers;

     - multi-national energy infrastructure companies;

                                        6
<PAGE>

     - large domestic and foreign utility companies;

     - affiliates of large local distribution companies;

     - affiliates of other interstate and intrastate pipelines; and

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

     Merchant Energy competes on the basis of price, access to production,
imbalance management, 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 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. The successful acquisition of new
business opportunities is dependent on Merchant Energy's ability to respond to
requests to provide new services, mitigate potential risks and maintain strong
business development, legal, financial and operational support teams with
experience in the marketplace.

                             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
natural gas liquids. It also provides well-ties and real-time information
services, including electronic wellhead gas flow measurement.

     Field Services' assets include natural gas gathering and natural gas
liquids pipelines, treating, processing and fractionation facilities in the San
Juan Basin, referred to as the Western Division; in the producing regions of
east and south Texas, the Permian Basin and the Gulf of Mexico, referred to as
the Central Division; and in Louisiana, referred to as the Eastern Division.

     Our Field Services segment also owns 7 percent of the common units of El
Paso Energy Partners L.P. El Paso Energy Partners is a master limited
partnership that provides gathering, transportation, fractionation, storage and
other related activities for producers of natural gas, natural gas liquids and
oil. A subsidiary of our parent company serves as the general partner of El Paso
Energy Partners.

                                        7
<PAGE>

     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>
                                                                                 AVERAGE THROUGHPUT(2)
                                       OWNERSHIP    MILES OF     THROUGHPUT    -------------------------
GATHERING & TREATING                   INTEREST    PIPELINE(1)   CAPACITY(2)   2001      2000      1999
--------------------                   ---------   -----------   -----------   -----   ---------   -----
                                       (PERCENT)                  (MMCFE/D)            (BBTUE/D)
<S>                                    <C>         <C>           <C>           <C>     <C>         <C>
Central Division(3)..................     100         9,480         5,220      3,769     1,375       891
Eastern Division.....................     100         1,661         1,162        491       835     1,184
Western Division.....................     100         5,555         1,200      1,197     1,039     1,262
El Paso Energy Partners..............       7           874           277        157       206       186
</Table>

<Table>
<Caption>
                                                                                   AVERAGE NATURAL GAS
                                                       AVERAGE INLET VOLUME(2)       LIQUIDS SALES(2)
                             OWNERSHIP      INLET      -----------------------   ------------------------
PROCESSING PLANTS            INTEREST    CAPACITY(2)   2001      2000     1999   2001      2000     1999
-----------------            ---------   -----------   -----   --------   ----   -----   --------   -----
                             (PERCENT)    (MMCF/D)             (BBTU/D)                  (MGAL/D)
<S>                          <C>         <C>           <C>     <C>        <C>    <C>     <C>        <C>
Central Division(3)........     100         1,730      1,566     296      242    3,120      399       202
Western Division...........     100           650        622     638      650    1,670    1,772     1,756
Eastern Division...........     100           135         63      65      140      163      173       264
Coyote Gulch...............      50           120        106      87       97       --       --        --
</Table>

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

(1) Mileage amounts are approximate for the total systems and have not been
    reduced to reflect Field Services' net ownership.

(2) All volumetric information reflects Field Services' net interest.

(3) The Central Division includes our acquisition of PG&E's Texas Midstream
    operations in December 2000. In February 2002, we announced our plan to sell
    9,400 miles of intrastate pipelines and 1,300 miles of gathering systems to
    El Paso Energy Partners.

  Regulatory Environment

     Some of Field Services' operations are subject to regulation by the FERC in
accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of
1978. Each entity subject to the FERC's regulation operates under separate FERC
approved tariffs with established rates, terms and conditions of service.

     Some of Field Services' operations are also subject to regulation by the
Railroad Commission of Texas under the Texas Utilities Code and the Common
Purchaser Act of the Texas Natural Resources Code. Field Services files the
appropriate rate tariffs and operates under the applicable rules and regulations
of the Railroad Commission.

     In addition, some of Field Services' operations are subject to the Natural
Gas Pipeline Safety Act of 1968, the Hazardous Liquid Pipeline Safety Act and
the National Environmental Policy Act. Each of the pipelines has a continuing
program of inspection designed to keep all of the facilities in compliance with
pollution control and pipeline safety requirements, and Field Services believes
that these systems are in compliance with applicable requirements.

  Markets and Competition

     Field Services competes with major interstate and intrastate pipeline
companies in transporting natural gas and natural gas liquids. 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 natural gas liquids.
Competition for throughput and natural gas supplies is based on a number of
factors, including price, efficiency of facilities, gathering system line
pressures, availability of facilities near drilling activity, service and access
to favorable downstream markets.

                                 ENVIRONMENTAL

     A description of our environmental activities is included in Part II, Item
8, Financial Statements and Supplementary Data, Note 10, and is incorporated
herein by reference.

                                        8
<PAGE>

                                   EMPLOYEES

     As of March 20, 2002, we had approximately 5,900 full-time employees, of
which 233 are subject to collective bargaining arrangements.

                                        9
<PAGE>

                      EXECUTIVE OFFICERS OF THE REGISTRANT

     Our executive officers as of March 20, 2002, are listed below.

<Table>
<Caption>
                 NAME                                            OFFICE                          AGE
                 ----                                            ------                          ---
<S>                                      <C>                                                     <C>
William A. Wise........................  Chairman of the Board, President and Chief Executive    56
                                         Officer
H. Brent Austin........................  Executive Vice President and Chief Financial Officer    47
Joel Richards III......................  Executive Vice President                                55
Peggy A. Heeg..........................  Executive Vice President: Law                           42
</Table>

     Mr. Wise became our Chairman of the Board, President and Chief Executive
Officer in December 1996. Mr. Wise has been Chief Executive Officer of El Paso
since January 1990 and Chairman of El Paso's Board of Directors since January
2001. He was also Chairman of El Paso's Board of Directors from January 1994
until October 1999. Mr. Wise became the President of El Paso in July 1998 and
also served in that capacity from January 1990 to April 1996. Mr. Wise is a
member of the Board of Directors of Praxair, Inc. and is the Chairman of the
Board of El Paso Energy Partners Company, the general partner of El Paso Energy
Partners, L.P.

     Mr. Austin has been our Executive Vice President and Chief Financial
Officer since June 1997. From December 1996 until June 1997, he was Senior Vice
President and Chief Financial Officer. Mr. Austin has been Executive Vice
President of El Paso since May 1995. He has been El Paso's Chief Financial
Officer since April 1992. Prior to that period, he served in various positions
with Burlington Resources Inc. and Burlington Northern Inc. Mr. Austin is a
member of the Board of Directors of El Paso Energy Partners Company, the general
partner of El Paso Energy Partners, L.P.

     Mr. Richards has been our Executive Vice President since June 1997. From
December 1996 until June 1997, he was Senior Vice President. Mr. Richards has
been Executive Vice President of El Paso since December 1996. From January 1991
until December 1996, he was Senior Vice President of El Paso.

     Ms. Heeg has been our Executive Vice President: Law and El Paso's Executive
Vice President and General Counsel since January 1, 2002. She was Senior Vice
President and Deputy General Counsel of El Paso from April 2001 to December 2001
and Vice President and Associate General Counsel for El Paso's regulated
pipelines from 1997 to 2001. Ms. Heeg has held various positions in the legal
department of Tenneco Energy and El Paso since 1996.

     Executive officers hold offices until their successors are elected and
qualified, subject to their earlier removal. Each of these elected officers also
hold offices and/or director positions with our affiliated entities.

ITEM 2. PROPERTIES

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

     We believe that we have satisfactory title to the properties owned and used
in our businesses, subject to liens for current taxes, liens incident to minor
encumbrances, and easements and restrictions that do not materially detract from
the value of these properties or our interests therein, 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 10, and is incorporated herein
by reference.

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

     None.

                                        10
<PAGE>

                                    PART II

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

     All of our common stock, par value $0.01 per share, is owned by El Paso and
is not publicly traded. Our Series A preferred stock is traded on the New York
Stock Exchange under the symbol EPG_p.

     We pay dividends on our common stock from time to time from legally
available funds that have been approved for payment by our Board of Directors.

     We pay dividends on our Series A preferred stock on a quarterly basis. The
dividend rate on our preferred stock is 8 1/4% per annum (2.0625% per quarter).
We pay dividends on March 31, June 30, September 30 and December 31 of each
year. All dividends payable on outstanding shares of our preferred stock for the
quarterly periods ending on or prior to December 31, 2001, have been paid in
full.

ITEM 6. SELECTED FINANCIAL DATA

<Table>
<Caption>
                                                            YEAR ENDED DECEMBER 31,
                                                  --------------------------------------------
                                                   2001      2000      1999     1998     1997
                                                  -------   -------   ------   ------   ------
                                                                 (IN MILLIONS)
<S>                                               <C>       <C>       <C>      <C>      <C>
Operating Results Data:(1)
  Operating revenues(2).........................  $32,982   $20,788   $9,670   $8,540   $8,842
  Merger-related costs and asset impairment
     charges(3).................................      108        11       75       --       --
  Income before extraordinary items and
     cumulative effect of accounting change.....      669       482      186      221      135
</Table>

<Table>
<Caption>
                                                               AS OF DECEMBER 31,
                                                  --------------------------------------------
                                                   2001      2000      1999     1998     1997
                                                  -------   -------   ------   ------   ------
                                                                 (IN MILLIONS)
<S>                                               <C>       <C>       <C>      <C>      <C>
Financial Position Data:(1)
  Total assets(2)...............................  $19,995   $19,465   $9,764   $8,393   $9,200
  Long-term debt, less current maturities.......    1,563     1,845    1,459    1,467    1,083
  Minority interests............................      356        51       88       74       80
  Stockholders' equity..........................    3,844     3,154    2,430    2,172    1,935
</Table>

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

(1) Our operating results and financial position reflect the acquisition in
    December 2000 of PG&E's Texas Midstream operations. This acquisition was
    accounted for as a purchase and therefore operating results are included in
    our results prospectively from the purchase date.

(2) The increase to our 2000 operating revenues and total assets reflects the
    significant growth in our Merchant Energy operations.

(3) Our 2001 and 2000 costs relate primarily to El Paso's merger with Coastal,
    and our 1999 costs relate primarily to El Paso's merger with Sonat.

                                        11
<PAGE>

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

                             RESULTS OF OPERATIONS

     For the three years ended December 31, 2001, 2000 and 1999, we had net
income of $717 million, $540 million and $173 million. The 2001 results included
merger-related costs and asset impairments totaling $108 million, or $73 million
after taxes, related to El Paso Corporation's merger with The Coastal
Corporation. See a discussion of these charges in Item 8, Financial Statements
and Supplementary Data, Note 3. In addition, we recorded an extraordinary gain
of $38 million, net of income taxes, as a result of a Federal Trade Commission
(FTC) ordered sale of our Midwestern Gas Transmission system. This order arose
as part of El Paso's merger with Coastal and is discussed further in Item 8,
Financial Statements and Supplementary Data, Note 2. We also recorded a
cumulative effect of accounting change of $10 million, net of income taxes,
related to our adoption of Emerging Issues Task Force Topic D-105 Accounting in
Consolidation for Energy Trading Contracts between Affiliated Entities When the
Activities of One but not Both Affiliates Are Within the Scope of Issue 98-10,
that we adopted during the fourth quarter of 2001. See a discussion of this
accounting change in Item 8, Financial Statements and Supplementary Data, Note
1. For the year ended December 31, 2000, merger-related charges were $11
million, or $7 million net of income taxes, and we recorded extraordinary gains
on the FTC ordered sales of our East Tennessee Natural Gas Company and our
interest in Oasis Pipeline Company totaling $58 million, net of income taxes.
The charge related to the sale of East Tennessee resulted from El Paso's merger
with Sonat Inc in 1999 and the charge from the sale of Oasis related to El
Paso's acquisition of Pacific Gas & Electric's Texas Midstream assets. For the
year ended December 31, 1999, merger-related costs and asset impairments related
to El Paso's merger with Sonat reduced net income by $75 million, or $52 million
after taxes. We also recorded a cumulative effect of accounting change of $(13)
million, net of income taxes. Net income for each of the three years ended
December 31, 2001, excluding the after-tax effects of these charges and
extraordinary items, would have been $742 million, $489 million and $238
million.

                                SEGMENT RESULTS

     Our three segments: Pipelines, Merchant Energy and Field Services are
strategic business units that offer a variety of different energy products and
services, each requiring different technology and marketing strategies. Our
operating results reflect the acquisition of PG&E's Texas Midstream operations
as of the purchase date. We evaluate segment performance based on earnings
before interest expense and taxes, or EBIT. To the extent possible, results of
operations have been reclassified to conform to the current business segment
presentation, although such results are not necessarily indicative of the
results which would have been achieved had the revised business segment
structure been in effect during those periods. Operating revenues and expenses
by segment include intersegment revenues and expenses which are eliminated in
consolidation. Because changes in energy commodity prices have a similar impact
on both our operating revenues and cost of products sold from period to period,
we believe that gross margin (revenue less cost of sales) provides a more
accurate and meaningful basis for analyzing operating results for the Merchant
Energy and the Field Services segments. For a further discussion of the
individual segments, see the discussion of our businesses beginning on page 1,
as well as Item 8, Financial Statements and Supplementary Data, Note 13.

                                        12
<PAGE>

     The following table presents EBIT by segment and in total, including the
merger-related costs and asset impairment charges discussed above, for each of
the three years ended December 31:

<Table>
<Caption>
                                                               2001        2000       1999
                                                              ------      ------      ----
                                                                     (IN MILLIONS)
<S>                                                           <C>         <C>         <C>
EARNINGS BEFORE INTEREST EXPENSE AND INCOME TAXES
Pipelines...................................................  $  322      $  354      $383
Merchant Energy.............................................     901         563         3
Field Services..............................................      81          88        78
                                                              ------      ------      ----
  Segment EBIT..............................................   1,304       1,005       464
                                                              ------      ------      ----
Corporate and other.........................................      (7)        (17)      (17)
                                                              ------      ------      ----
  Consolidated EBIT.........................................  $1,297      $  988      $447
                                                              ======      ======      ====
</Table>

PIPELINES

     Our Pipelines segment operates our interstate pipeline business. Our
pipeline systems operate under separate tariffs that govern their operations,
terms and conditions of service and rates. Operating results for our pipeline
systems have generally been stable because the majority of the revenues are
based on fixed reservation charges. As a result, we expect changes in this
aspect of our business to be primarily driven by regulatory actions, system
expansions and contractual events. Commodity or throughput-based revenues
account for a smaller portion of our operating results. These revenues vary from
period to period, and are impacted by factors such as weather, operating
efficiencies, competition from other pipelines and fluctuations in natural gas
prices. Results of operations of the Pipelines segment were as follows for each
of the three years ended December 31:

<Table>
<Caption>
                                                               2001     2000     1999
                                                              ------   ------   ------
                                                                   (IN MILLIONS)
<S>                                                           <C>      <C>      <C>
Operating revenues..........................................  $  730   $  776   $  852
Operating expenses..........................................    (429)    (441)    (492)
Other income................................................      21       19       23
                                                              ------   ------   ------
  Earnings before interest and income taxes.................  $  322   $  354   $  383
                                                              ======   ======   ======
          Total throughput (BBtu/d)(1)......................   4,441    4,375    4,265
                                                              ======   ======   ======
</Table>

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

(1) Throughput volumes exclude those related to pipeline systems sold in
    connection with El Paso's Coastal and Sonat mergers including the Midwestern
    Gas Transmission and East Tennessee Natural Gas systems.

     YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 2000

     Operating revenues for the year ended December 31, 2001, were $46 million
lower than the same period in 2000. This decrease was due to lower 2001 revenues
resulting from remarketed contracts on TGP during 2000 and the sales of the
Midwestern Gas Transmission system in April 2001 and the East Tennessee Natural
Gas system in the first quarter of 2000, including contract quantity reductions
or cancellations on our pipeline system by customers of our affiliate, East
Tennessee Natural Gas Company, resulting from the FTC ordered sale of this
system. Also contributing to the decrease were lower transportation revenues on
throughput in 2001 as a result of higher proportion of short versus long hauls
compared to 2000. Our revenues from period to period are impacted not only by
the overall volume of gas transported, but the distances this gas is shipped on
our system. Partially offsetting the decrease was higher sales of excess natural
gas in 2001, the favorable resolution of issues related to natural gas purchase
contracts and higher revenues from other transportation services.

     Operating expenses for the year ended December 31, 2001, were $12 million
lower than the same period in 2000. The decrease was due to lower corporate
allocations and operating expenses as a result of cost savings following our
parent company's merger with Coastal, decreased depreciation expense resulting
from the retirement of assets and reduced operating and depreciation expenses
from the sales of the Midwestern and

                                        13
<PAGE>

East Tennessee systems. The decrease was partially offset by higher electric
compression costs in 2001 and higher project development costs.

     YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999

     Operating revenues for the year ended December 31, 2000, were $76 million
lower than the same period in 1999. The decrease was due to the impact of the
sale of our East Tennessee Pipeline system in the first quarter of 2000, which
El Paso was required to sell under an FTC order as a condition to completing the
Sonat merger. Also contributing to the decrease was the impact of customer
settlements and contract terminations in 2000, and the favorable resolution of
regulatory issues and sale of emission credits in 1999. The decreases were
partially offset by higher revenues from transportation and other services due
to improved average throughput in 2000.

     Operating expenses for the year ended December 31, 2000, were $51 million
lower than the same period in 1999. The decrease was due to cost efficiencies
following El Paso's merger with Sonat and lower operating costs on our East
Tennessee Pipeline system, which was sold in the first quarter of 2000.

     Other income for the year ended December 31, 2000, was $4 million lower
than the same period in 1999 primarily due to a gain on the sale of non-pipeline
assets recorded in 1999.

MERCHANT ENERGY

     Our Merchant Energy segment is involved in a wide range of activities in
the wholesale energy markets, including asset ownership, customer origination,
marketing and trading and financial services. Each of the markets served by
Merchant Energy is highly competitive and is influenced directly or indirectly
by energy market economics.

  Asset Ownership

     Merchant Energy's asset ownership activities include domestic and
international power plants and an emerging LNG business. In its power asset
business, Merchant Energy owns or has interests in 77 plants in 16 countries.
The segment's domestic power activities are principally conducted through
Chaparral Investors, L.L.C., an unconsolidated affiliate in which Merchant
Energy has a 20 percent ownership interest.

     Chaparral. Chaparral was formed in 1999. Through its subsidiaries,
Chaparral (also referred to as Electron) owns domestic power assets and is
funded with third party capital (80%) and El Paso capital (20%). A subsidiary in
our Merchant Energy segment manages the daily activities of Chaparral's assets
and investments and are paid an annual management fee. The basic strategy of
Chaparral is:

     - to acquire power facilities with attractive power contracts;

     - to develop facilities that will operate under long-term tolling
       agreements;

     - to restructure the power sales, fuel supply and credit agreements of
       PURPA facilities;

     - to monetize these restructured arrangements to fund operations and grow
       the venture; and

     - to operate these facilities in a fully deregulated environment in a
       manner that enhances their value.

     Chaparral was formed in order to obtain low cost financing to grow new
business activities and to generate a stable fee-based income stream. Merchant
Energy's annual management fee is equal to 20% of the net present value of the
assets of Chaparral and must be approved by the third party investor. This net
present value, or NPV, represents the present value of anticipated future cash
flows of Chaparral's assets, net of its liabilities, less the estimated cost to
liquidate all third party capital. As of December 31, 2001, Chaparral held
assets with an NPV totaling approximately $925 million.

     As of December 31, 2001, Chaparral's total assets were $2.5 billion and its
liabilities were $1.6 billion. Total third party capital in Chaparral was
approximately $1.15 billion, of which the debt component was $1.0 billion. In
order to lower the cost of this debt, El Paso provided a contingent equity
support arrangement to the third party debtholders. El Paso plans to amend this
arrangement and replace it with an El Paso financial guaranty in 2002.

                                        14
<PAGE>

     The future success of Chaparral will be dependent upon its ability to
successfully restructure its existing assets, as well as acquire additional
power facilities. Chaparral may face increased competition in the future for
properties and facilities that are increasingly complicated to acquire and
restructure. In addition, if not renegotiated or renewed, the debt financing
that supports Chaparral matures in the first quarter of 2003. While it is our
intent to renew these agreements, there are no guarantees that the financial
investors will continue to participate or that third party capital will be
available for investment.

     Merchant Energy conducts a variety of transactions with Chaparral and
generates earnings in several ways, including a performance-based management
fee, equity earnings from Chaparral's activities and margins on risk management
activities where Merchant Energy serves as the commodity provider for many of
Chaparral's fuel and power purchase contracts. Chaparral also reimburses
Merchant Energy for general and administrative expenses incurred on its behalf.
During 2001, Merchant Energy earned $147 million in management fees from
Chaparral and was reimbursed $20 million for general and administrative
expenses. It also recognized $75 million in equity earnings. For 2002, the
management fee will increase to approximately $185 million as approved by
Chaparral's third party investor in the fourth quarter of 2001. This management
fee increase reflects the growth that has occurred in the Chaparral asset
portfolio. Assumptions used in establishing the annual management fee include
estimates of future energy prices, future demand for power, timing and terms of
contract restructurings and future interest rates. These assumptions are based
on a combination of quoted market prices and rates, models which project future
market changes and anticipated demand, and other variables. Changes in these
assumptions can impact the annual management fee from year to year and these
changes can be material.

     From time to time, we and other El Paso affiliates enter into transactions
with Chaparral and its affiliates to sell power assets. Merchant Energy's
fiduciary responsibilities under its management agreement with Chaparral require
that these transactions be entered into at fair and reasonable values. To ensure
fairness, significant transactions are evaluated and approved by the third party
investor of Chaparral as well as El Paso's Board of Directors. During 2001,
Chaparral acquired power assets from us with a fair value of $94 million. We did
not recognize any gains or losses on these transactions.

     International Power Assets and Gemstone. Internationally, Merchant Energy's
power assets consist primarily of investments in joint ventures that construct
and operate power facilities and other infrastructure assets around the world.
In Brazil, these activities are conducted through Gemstone, an unconsolidated
affiliate through which Merchant Energy plans to expand its power investments in
that country. Gemstone was formed in late 2001 with a third party investor
primarily to generate low-cost funds for financing power plants in Brazil and to
reduce risk through the introduction of third party equity. Total third party
capital in Gemstone as of December 31, 2001 was $1 billion, of which the debt
component was $950 million. To lower the cost of this debt, El Paso provided a
contingent equity support arrangement to the third party debtholders. El Paso
plans to amend this arrangement and replace it with an El Paso financial
guaranty in 2002.

     Brazil's power infrastructure has primarily been based on the use of
hydroelectric power generation. The success of Gemstone in the future will be
based on the demand for natural gas fired generation in Brazil, which may be
significantly impacted by the availability of competing generation, such as
hydroelectric power generation, which is less expensive to operate and more
abundant. Furthermore, there are numerous risks in operating internationally
which could impact Gemstone's ultimate success.

     Earnings from Merchant Energy's international power activities, including
Gemstone, are derived primarily through equity earnings from these investments
and will be dependent on the ultimate success of privately owned power
generation and infrastructure development in countries where Merchant Energy
does business. During 2001, Merchant Energy recorded net equity income from
Gemstone of $2 million.

     Liquified Natural Gas (LNG). In addition to its power business, Merchant
Energy has an emerging global LNG operation. In 2001, Merchant Energy increased
the scope of its activities in LNG, with full operations expected in 2003 and
2004. The success of this business will be based substantially on the worldwide
supply of natural gas and demand for LNG which will depend on strong natural gas
prices and LNG shipping and terminalling infrastructure.

                                        15
<PAGE>

  Customer Origination, Marketing and Trading

     Merchant Energy's customer origination, marketing and trading activities
provide energy supply and risk management solutions for its customers and
affiliates involving natural gas, power and other energy commodities. Merchant
Energy assists its customers with energy supply aggregation, storage and
transportation management and provides them with an array of risk management
products. Merchant Energy also conducts a substantial energy trading business
that executes proprietary trading strategies and manages the segment's risk
across multiple commodities and over seasonally fluctuating energy demands using
consistent methodologies. During 2001 and 2000, U.S. energy supply and demand
resulted in substantial volatility in the energy markets that significantly
impacted Merchant Energy's earnings.

     Merchant Energy's customer origination, marketing and trading groups
account for their activities using mark-to-market accounting. Under this
accounting method, financial instruments, physical commodity positions and
contractual energy-related transactions are recorded on the balance sheet and
the income statement at their fair value at the time they are entered into.
Subsequent to their inception, the transactions continue to be adjusted in the
balance sheet and income statement for changes in their fair value until they
are settled. Determining the fair value of these positions at inception and
until settlement principally involves the use of actively quoted prices and, to
a lesser degree, other valuation methods, including models that rely on actively
quoted prices. Approximately 9% of the value of our mark-to-market portfolio is
based on model valuations (i.e., not on active market quotes). Most of these
models are options-based valuations and involve contracts related to physical
assets. Examples of contracts that are generally valued using models include
natural gas pipeline capacity, natural gas storage contracts and, to a lesser
extent, power plant tolling agreements. Modeling allows us to value these
contracts, as well as manage them more effectively, providing lower cost service
to our customers, and to effectively measure and manage the risk associated with
them on a daily basis. Almost all of the model-based valuations we employ are
spread option valuations, such as location spread options (pipeline capacity),
time spread options (natural gas storage capacity) and spark spread options
(natural gas-fired power plant tolling). The price data underlying these models
is based, in part, on market data and our estimates of future prices for periods
in which market data is limited. An important variable in these models is the
volatility of the prices underlying the contracts and the correlation of the
prices underlying the contracts. There is limited market price data related to
correlations and volatilities although significant implicit data does exist. We
use this implicit market data and historical data to determine volatilities and
correlation for calculation of these models. We believe these calculations to be
reliable predictors of value over time. In addition, Merchant Energy maintains a
risk controls group that verifies all market price data for accuracy,
independently of the marketing and trading groups and this group conducts these
activities on both actively quoted and model-derived information. Further, to
the extent there is uncertainty of the amounts we will ultimately realize from
these transactions, we adjust the amounts we recognize as income until these
uncertainties are resolved. These estimates are adjusted as assumptions change
or as transactions move closer to settlement and better estimates become
available.

     As of December 31, 2001, the fair value of our trading-related price risk
management activities is $1,337 million, and total margins generated from these
activities during 2001 were $675 million.

     The following table details the fair value of Merchant Energy's trading
price risk management activities by year of maturity and valuation methodology.
The amounts reflected as prices actively quoted are based on values determined
by market quotes and other actively traded data, primarily NYMEX and other
exchange-based information, including broker quotes. The amounts reflected as
prices based on models and

                                        16
<PAGE>

other valuation methods represent the fair value of contracts calculated based
on internal models using the methods discussed above.

 FAIR VALUE OF TRADING PRICE RISK MANAGEMENT CONTRACTS AS OF DECEMBER 31, 2001

<Table>
<Caption>
                                        MATURITY    MATURITY   MATURITY   MATURITY   MATURITY   TOTAL
                                        LESS THAN    1 TO 3     4 TO 5    6 TO 10     BEYOND     FAIR
SOURCE OF FAIR VALUE                     1 YEAR      YEARS      YEARS      YEARS     10 YEARS   VALUE
--------------------                    ---------   --------   --------   --------   --------   ------
                                                                (IN MILLIONS)
<S>                                     <C>         <C>        <C>        <C>        <C>        <C>
Prices actively quoted................    $401        $384       $266       $102       $ 61     $1,214
Prices based on models and other
  valuation methods...................      39          76         47        (12)       (27)       123
                                          ----        ----       ----       ----       ----     ------
          Total net trading assets....    $440        $460       $313       $ 90       $ 34     $1,337
                                          ====        ====       ====       ====       ====     ======
</Table>

     A reconciliation of our 2001 trading activities is as follows (in
millions):

<Table>
<S>                                                           <C>
Fair value of net trading assets as of December 31, 2000....  $ 2,143
                                                              -------
Fair value of contracts settled during the period...........   (1,973)
Initial recorded value of new contracts.....................      160
Change in fair value of contracts...........................      812
Changes in fair value attributable to changes in valuation
  techniques................................................        2
Cumulative effect of change in accounting principle.........       17
Other.......................................................      176
                                                              -------
Net change in contracts outstanding during the period.......     (806)
                                                              -------
Fair value of net trading assets as of December 31,
  2001(1)...................................................  $ 1,337
                                                              =======
</Table>

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

(1) At December 31, 2001, net assets from non-trading price risk management
    activities were $23 million, and total net assets from all of our price risk
    management activities were $1,360 million.

     The fair value of contracts settled during the period represents the
amounts of traded contracts settled in cash, through physical delivery of a
commodity or by a claim to cash as accounts receivable or payable. The initial
recorded value of new contracts includes the fair value of origination
transactions at the time the transaction is initiated. The change in fair value
of contracts during the year represents the change in value of contracts from
the beginning of the period, or the date of their origination, until their
settlement or, if not settled, until the end of the period. The cumulative
effect of change in accounting principle includes the effect of our adoption of
EITF Issues Topic D-105 in 2001. Included in other is the effect of natural gas
storage purchases, premiums paid on option contracts and the values of contracts
transferred to our trading portfolio as a result of a change in the manner in
which these contracts were managed following the Coastal merger.

  Financial Services

     In the financial services area, Merchant Energy conducts energy financing
activities through its ownership of EnCap and Enerplus. EnCap manages four
separate oil and natural gas investment funds in the U.S., and serves as an
investment advisor to one fund in Europe. EnCap also facilitates investment in
emerging energy companies and earns a return from these investments. Enerplus,
which was acquired in 2000, is a Canadian investment management company which
conducts fund management activities similar to EnCap, but in Canada. Results
from Merchant Energy's financial services activities are based on a combination
of management fees and market based earnings on the investments held by these
companies.

                                        17
<PAGE>

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

<Table>
<Caption>
                                                             2001      2000      1999
                                                            -------   -------   -------
                                                                   (IN MILLIONS)
<S>                                                         <C>       <C>       <C>
Trading gross margin......................................  $   675   $   403   $   103
Operating and other revenues..............................      396       294       105
Operating expenses........................................     (483)     (264)     (299)
Other income..............................................      313       130        94
                                                            -------   -------   -------
  EBIT....................................................  $   901   $   563   $     3
                                                            =======   =======   =======

Volumes (excludes intrasegment transactions):
  Physical
     Natural gas (BBtue/d)................................    8,938     6,899     6,713
     Power (MMWh).........................................  220,668   116,749    79,361
     Other energy commodities (MBbls).....................   19,444     7,772     4,990
  Financial Settlements (Bbtue/d).........................  143,096    98,664    68,678
</Table>

     YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 2000

     Trading gross margin consists of revenues from commodity trading and
origination activities less costs of commodities sold. For the year ended
December 31, 2001, these gross margins were $272 million higher than the same
period in 2000. The increase was primarily due to higher trading margins in
natural gas and power as a result of increased trading volumes and price
volatility as well as increased income from transactions originated during 2001.
The increase in trading margins was partially offset by reserves established as
a result of the bankruptcy of Enron Corp. in December 2001.

     Merchant Energy has conducted trading activities and held derivative
positions with Enron Corp. and its subsidiaries. In December of 2001, Enron and
certain of its subsidiaries sought protection from its creditors under Chapter
11 of the U.S. Bankruptcy Code. Following this filing, Merchant Energy
terminated all contracts with the Enron subsidiaries that filed for bankruptcy.
This resulted in the transfer of Merchant Energy's net derivative positions with
Enron out of price risk management activities to accounts receivable. In
addition, Merchant Energy established reserves on these receivables that it
believes are adequate based on the amounts it expects to collect through the
bankruptcy. In the first quarter of 2002, Merchant Energy asserted a claim
against Enron on the cancelled contracts.

     Merchant Energy is a provider of power and natural gas to the state of
California. During the latter half of 2000 and continuing into the first half of
2001, California experienced sharp increases in wholesale power prices and
natural gas prices due to energy shortages resulting, in part, from a
combination of unusually warm summer weather followed by higher winter demand,
low gas storage levels, lower hydroelectric power generation and maintenance
downtime of significant generation facilities. As a result, the two major
California utilities, Southern California Edison and Pacific Gas & Electric,
defaulted on payments to creditors and accumulated substantial under-collections
from customers. This resulted in their credit ratings being downgraded in 2001
from investment grade to below investment grade, and in April 2001, Pacific Gas
& Electric filed for bankruptcy. During 2001, we recognized revenues from
Pacific Gas & Electric and Southern California Edison that we believe are
appropriate based on their improving financial condition. This resulted in our
recognition of income on a portion of these transactions during the fourth
quarter based on improved credit exposure to customers in the state.

     Operating and other revenues consist of revenues from domestic and
international power generation facilities and investments, including our
management fee from Chaparral and revenues from EnCap and the other financial
services businesses of Merchant Energy. For the year ended December 31, 2001,
operating and other revenues were $102 million higher than the same period in
2000. The increase resulted from higher management fees from Chaparral, higher
revenues from EnCap and our other financial services, and revenues from the CEBU
power project, a Philippine project in which we acquired an additional interest
and began

                                        18
<PAGE>

consolidating during the first quarter of 2001. Offsetting the increase were
revenues recorded in 2000 on our West Georgia power generation facility that was
sold in the fourth quarter of 2000.

     Operating expenses for the year ended December 31, 2001, were $219 million
higher than the same period in 2000. The increase was primarily a result of
higher operating expenses resulting from the expansion of our operations in
Europe, Mexico, Brazil, Singapore, our LNG business and the consolidation of the
CEBU power project. This increase was partially offset by lower costs related to
the West Georgia plant which was sold to Chaparral in the fourth quarter of
2000.

     Other income for the year ended December 31, 2001, was $183 million higher
than the same period in 2000. The increase was the result of marketing, agency
and technical services fees related to the development of the Macae power
project in Brazil, and higher equity earnings from Chaparral resulting primarily
from the completion of power contract restructurings. These increases were
partially offset by lower earnings on an Argentine investment, and gains from
the sale of a portion of our East Asia Power project occurring in the first
quarter of 2000.

     YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999

     Trading gross margin for the year ended December 31, 2000, was $300 million
higher than the same period in 1999. Trading margins increased due to
significant price volatility in natural gas and power markets that increased the
value of our trading portfolio during 2000 versus 1999. Also contributing to the
increase was higher income from transactions originated in 2000.

     Operating and other revenues for the year ended December 31, 2000, were
$189 million higher than the same period in 1999. The increase was due to asset
management fees earned from Chaparral, which began operations during the fourth
quarter of 1999, revenues on the West Georgia power project, a seasonal peaking
facility that began operating in June 2000, and the consolidation of a Brazilian
power project in the latter part of 1999. Revenues on EnCap's financial services
activities in 2000 also contributed to the increase.

     Operating expenses for the year ended December 31, 2000, were $35 million
lower than the same period in 1999. The decrease was due to higher reimbursement
in 2000 of general and administrative costs relating to Chaparral, a 1999 charge
to eliminate a minority investor in Sonat's marketing joint venture following
the Sonat merger, and 1999 asset writedowns and charges to consolidate
accounting policies with those of Sonat following the merger. These decreases
were partially offset by higher general and administrative expenses and project
development costs relating to international projects in 2000.

     Other income for the year ended December 31, 2000, was $36 million higher
than the same period in 1999. The increase was due to higher earnings from CE
Generation, a power project acquired in March 1999 and the benefit realized from
the formation of our East Asia Power joint venture in March 2000. These
increases were partially offset by lower equity earnings from investments in
various international projects, primarily our investment in East Asia Power in
the Philippines.

FIELD SERVICES

     Our Field Services segment provides a variety of services for the midstream
component of our operations, including gathering and treating of natural gas,
processing and fractionation of natural gas, natural gas liquids and natural gas
derivative products, such as butane, ethane, and propane. In addition, Field
Services owns 7 percent of El Paso Energy Partners, L.P.'s common units. A
subsidiary of El Paso Corporation serves as the partnership's general partner.

     Field Services attempts to balance its earnings from its operating
activities through a combination of fixed-fee based and market-based services. A
majority of Field Services gathering and treating operations earn margins from
fixed-fee-based services. However, some of these operations earn margins from
market-based rates. Revenues for these market-based rate services are the
product of a market price, usually related to the monthly natural gas price
index and the volume gathered.

                                        19
<PAGE>

     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 to return to the producer a Btu
equivalent amount of natural gas. Under our percentage-of-proceeds contracts and
make-whole contracts, Field Services may have more sensitivity to price changes
during periods when natural gas and liquid prices are volatile.

     In December 2000, Field Services completed the purchase of Pacific Gas &
Electric's (PG&E's)Texas Midstream operations for $887 million, including $527
million of assumed debt. This acquisition was accounted for as a purchase. The
assets acquired consist of 7,500 miles of intrastate natural gas transmission
and natural gas liquids pipelines that transport approximately 2.8 Bcf/d, nine
natural gas processing plants that process 1.5 Bcf/d and rights to 7.2 Bcf of
natural gas storage capacity. These assets serve a majority of the metropolitan
areas and the largest industrial load centers in Texas, as well as numerous
natural gas trading hubs. Results from this acquisition are reflected in our
results of operations from the date of purchase.

     In March 2001, we sold some of the acquired natural gas liquids
transportation and fractionation assets to El Paso Energy Partners for
approximately $133 million. The assets sold included more than 600 miles of
natural gas liquids gathering and transportation pipelines and three
fractionation plants located in south Texas.

     In February 2002, we announced the sale of additional midstream assets to
El Paso Energy Partners for total consideration of $750 million. The primary
assets to be sold include:

     - 9,400 miles of intrastate transmission pipelines;

     - 1,300 miles of gathering systems in the Permian Basin; and

     - a 42.3 percent non-operating interest in the Indian Basin gas processing
       and treating plant and associated gathering lines.

     Proceeds will be approximately $554 million in cash and approximately $6
million in El Paso Energy Partners common units, along with the partnership's
interest in an offshore tension leg platform and a nine percent overriding
royalty interest that the partnership holds in a producing field. These assets
have a combined fair value estimated at approximately $190 million. We expect to
complete the transaction in March 2002. The sale of these assets is contingent
upon receiving customary regulatory approvals and execution of definitive
agreements. We do not anticipate a material gain or loss on these transactions.

     Field Services' operating results and an analysis of those results are as
follows for each of the three years ended December 31:

<Table>
<Caption>
                                                                2001           2000           1999
                                                              ---------      ---------      ---------
                                                              (IN MILLIONS EXCEPT VOLUMES AND PRICES)
<S>                                                           <C>            <C>            <C>
Gathering, treating and processing gross margin.............   $  405         $  249         $  207
Operating expenses..........................................     (326)          (165)          (161)
Other income................................................        2              4             32
                                                               ------         ------         ------
  EBIT......................................................   $   81         $   88         $   78
                                                               ======         ======         ======
Volume and prices
  Gathering and treating
     Volumes (BBtu/d).......................................    5,266          2,934          3,821
                                                               ======         ======         ======
     Prices ($/MMBtu).......................................   $ 0.13         $ 0.17         $ 0.14
                                                               ======         ======         ======
  Processing
     Volumes (inlet BBtu/d).................................    2,394          1,066          1,032
                                                               ======         ======         ======
     Prices ($/MMBtu).......................................   $ 0.16         $ 0.18         $ 0.12
                                                               ======         ======         ======
</Table>

                                        20
<PAGE>

     YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 2000

     Total gross margin for the year ended December 31, 2001, was $156 million
higher than the same period in 2000. The increase was primarily due to higher
volumes as a result of our acquisition of PG&E's Texas Midstream operations in
December 2000. Volumes also increased as a result of our acquisition of the
Indian Basin processing plant in the second quarter of 2000 combined with an
increase in Indian Basin's capacity in 2001. Also contributing to the increase
were higher margins in the San Juan Basin due to higher natural gas liquids and
natural gas prices in the first half of 2001 partially offset by lower prices in
the second half of 2001. These increases were partially offset by higher
processing costs associated with a new processing arrangement with El Paso
Energy Partners at the Chaco processing facility in the fourth quarter of 2001.
For the year ended December 31, 2001, average gathering, treating and processing
rates were lower compared to 2000 due primarily to the different mix of assets
and contract terms resulting from the acquisition of PG&E's Texas Midstream
operations.

     Operating expenses for the year ended December 31, 2001, were $161 million
higher than the same period in 2000. The increase was a result of higher
operating, depreciation and other expenses primarily from the addition of PG&E's
Texas Midstream operations, increased general and administrative and
merger-related costs. See a discussion of merger-related costs at Item 8,
Financial Statements and Supplementary Data, Note 3.

     YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999

     Total gross margin for the year ended December 31, 2000, was $42 million
higher than the same period in 1999. The increase was a result of higher average
gathering rates, predominately in the San Juan Basin, which are substantially
indexed to natural gas prices and higher average condensate prices. Also
contributing to the increase were higher natural gas liquids prices in 2000 and
our acquisition of the Indian Basin processing plant in the second quarter of
2000. The increase was partially offset by lower gathering and treating volumes
due to the sale of El Paso Intrastate-Alabama, a gathering system in the
coal-bed methane producing regions of Alabama, to El Paso Energy Partners in
March 2000.

     Operating expenses for the year ended December 31, 2000, were $4 million
higher than the same period in 1999 due to higher depreciation and amortization
from assets transferred from El Paso Natural Gas to Field Services following a
FERC order as well as the December 2000 impairment charge related to the Needle
Mountain LNG processing facility due to unrecoverability of costs. The increase
was partially offset by the impairment of gathering assets in 1999, lower costs
for labor and benefits and cost recoveries from managed facilities.

     Other income for the year ended December 31, 2000, was $28 million lower
than the same period in 1999. The decrease was primarily due to net gains in
1999 from the sale of our interest in the Viosca Knoll gathering system to El
Paso Energy Partners in June 1999, as well as lower equity earnings in 2000
following the sale of our interest in Viosca Knoll.

INTEREST AND DEBT EXPENSE

     YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 2000

  Non-affiliated Interest and Debt Expense

     Non-affiliated interest and debt expense for the year ended December 31,
2001, was $7 million higher than 2000 due to long-term debt assumed by Field
Services in relation to its acquisition of PG&E's Texas Midstream operations in
December 2000.

  Affiliated Interest Expense

     Affiliated interest expense, net for the year ended December 31, 2001, was
$33 million higher than 2000, primarily due to an increase in advances from El
Paso for on-going capital projects, investment programs and operating
requirements partially offset by lower short-term interest rates on average
advances to El Paso under our cash management program with them.

                                        21
<PAGE>

     YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999

  Non-affiliated Interest and Debt Expense

     Non-affiliated interest and debt expense for the year ended December 31,
2000, was $6 million higher than 1999 due to higher finance costs on
international projects, higher Merchant Energy over-the-counter margins, and
higher average commercial paper borrowings.

  Affiliated Interest Expense

     Affiliated interest expense for the year ended December 31, 2000, was $82
million higher than 1999 due to an increase in advances from El Paso for ongoing
capital projects, investment programs, and operating requirements. The increase
was also due to higher average interest rates with El Paso in 2000.

MINORITY INTEREST

     YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 2000

     Minority interest for the year ended December 31, 2001, was $4 million
higher than in 2000. This increase is due to higher balances in minority
interest as a result of the issuance of preferred interests in Topaz Investors
L.L.C. (part of our Gemstone transaction).

INCOME TAXES

     Income tax expense for the years ended December 31, 2001, 2000, and 1999
was $320 million, $242 million and $85 million. These amounts resulted in
effective tax rates of 32 percent, 33 percent, and 31 percent. Differences in
our effective tax rates from the statutory tax rate of 35 percent were primarily
a result of the following factors:

     - state income taxes;

     - earnings from unconsolidated equity investees where we anticipate
       receiving dividends;

     - foreign income taxed at different rates; and

     - the non-deductible portion of merger-related costs.

     For a reconciliation of the statutory rate of 35 percent to the effective
tax rates, see Item 8, Financial Statements and Supplementary Data, Note 4.

                        LIQUIDITY AND CAPITAL RESOURCES

CASH FROM OPERATING ACTIVITIES

     Net cash provided by our operating activities was $2,487 million for the
year ended December 31, 2001, compared to net cash used of $1,025 million for
the same period of 2000. The increase was primarily due to physical liquidations
of net derivative trading positions related to our price risk management
activities, coupled with lower cash payments in 2001 for charges related to
broker and over-the-counter margins.

CASH FROM INVESTING ACTIVITIES

     Net cash used in our investing activities was $1,352 million for the year
ended December 31, 2001. Our investing activities principally consisted of
additions to property, plant and equipment primarily in our Merchant Energy and
Pipelines Segments for expansion and construction projects. We had additions to
joint ventures and investments in unconsolidated affiliates, primarily related
to our investment in Gemstone, five coal-fired power plants and two
international power companies located in Brazil and China. Our additions to
investments also consist of short-term notes from unconsolidated affiliates
related to East Coast Power which was repaid to us during the year. Our
investing activities also included the buyout of Coastal's (our affiliate's)
interest in El Paso Merchant Energy, L.P. for $114 million. In March 2001, we
exchanged trading contracts

                                        22
<PAGE>

and related assets with Coastal in exchange for units in our subsidiary, El Paso
Merchant Energy, L.P. The exchange was based on the estimated fair value of the
assets and units exchanged. Cash inflows from investment-related activities
included proceeds from the sale of our Midwestern Gas Transmission system.

CASH FROM FINANCING ACTIVITIES

     Net cash used in our financing activities was $1,117 million for the year
ended December 31, 2001. During 2001, we retired long-term debt, paid dividends
and paid advances to El Paso. Cash provided from our financing activities
included the issuance of preferred securities related to one of our consolidated
subsidiaries associated with Gemstone and borrowings from commercial paper.

     Our significant repayment activities during 2001 are presented below. These
amounts do not include borrowings or repayments on our short-term financing
instruments with an original maturity of three months or less, including our
commercial paper program. We did not have significant borrowing activities
during 2001.

<Table>
<Caption>
    DATE             COMPANY               TYPE       INTEREST RATE     PRINCIPAL
    ----             -------               ----       -------------     ---------
                                                                      (IN MILLIONS)
<S>           <C>                     <C>             <C>             <C>
Retirements
2001
  February    El Paso Tennessee       Long-term debt    9.875%            $ 24
  August      EPEC Corporation        Long-term debt    9.625%              13
  Jan.-Dec.   El Paso Field Services  Long-term debt   Various             347
</Table>

  Credit Facilities and Available Capacity

     We use a commercial paper program to manage our short-term cash
requirements. TGP, our subsidiary, is eligible to borrow up to $1 billion under
this program.

     Our parent, El Paso, maintains a 3-year, $1 billion, revolving credit and
competitive advance facility under which it can conduct short-term borrowings
and other commercial credit transactions. This facility expires in 2003 and TGP
is a designated borrower under the facility. In June 2001, El Paso replaced an
existing 364-day revolving credit facility with a renewable $3 billion, 364-day
revolving credit and competitive advance facility. TGP is also a designated
borrower under this new facility. The interest rate on these facilities varies
and was based on LIBOR plus 50 basis points at December 31, 2001. No amounts
were outstanding under these facilities at December 31, 2001.

     As of December 31, 2001, TGP had $200 million under a shelf registration
statement on file with the Securities and Exchange Commission.

     The availability of borrowings under these credit and borrowing agreements
is subject to specified conditions, which we believe are currently being met.
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.

  Future Liquidity

     We rely on cash generated from our internal operations and funding from our
parent company as our primary sources of liquidity. We also supplement our
internally generated cash through our commercial paper program and available
credit facility. From time to time, we also use structured financial products.
We expect that our future funding for working capital needs, capital
expenditures, acquisitions, other investing activities, long-term debt
repayments, dividends and other financing activities will continue to be
provided from these sources.

     Our cash from internal operations may change in the future due to a number
of factors, some of which we cannot control, including the price we will receive
for the products we sell and services we provide, the demand for our products
and services, margin requirements resulting from significant increases or
decreases in commodity prices, operational risks, and other factors. Our ability
to draw upon our available credit facilities will be dependent upon our ability
and our parent company's ability to comply with the conditions and

                                        23
<PAGE>

requirements of these credit facilities, all of which we believe are currently
being met. Funding from the capital markets for commercial paper, long-term debt
or equity or other structured financial products may be impacted by lack of
liquidity for our industry segment, a change in our and our parent's credit
rating or changes in market conditions.

               CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

     In the course of our business activities, we enter into a variety of
contractual obligations and commercial commitments. Some of these result in
direct obligations that are reflected in our balance sheet while others are
commitments, some firm and some based on uncertainties, that are not reflected
in our underlying financial statements.

CONTRACTUAL CASH OBLIGATIONS

     The following table summarizes our contractual cash obligations by payment
due date. Each of these obligations is discussed in further detail below (in
millions):

<Table>
<Caption>
                                                                           PAYMENTS DUE BY PERIOD
                                                               ----------------------------------------------
                                                               LESS THAN                               AFTER
          CONTRACTUAL CASH OBLIGATIONS              TOTAL       1 YEAR      1-3 YEARS    4-5 YEARS    5 YEARS
          ----------------------------            ---------    ---------    ---------    ---------    -------
<S>                                               <C>          <C>          <C>          <C>          <C>
Short-term cash obligations.....................   $  499       $  499        $ --         $ --       $   --
Long-term cash obligations(1)...................    1,643           68          34           54        1,487
Minority interests(2)...........................      356           --         300           --           56
Operating leases................................       24            7           6            4            7
Capital commitments and purchase obligations....    1,627          500         148          163          816
                                                   ------       ------        ----         ----       ------
  Total contractual cash obligations............   $4,149       $1,074        $488         $221       $2,366
                                                   ======       ======        ====         ====       ======
</Table>

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

(1) Our long-term cash obligations exclude $12 million in unamortized debt
    discounts as of December 31, 2001.
(2) The maturity schedule for these instruments is based on the expiration
    period of the underlying agreements.

     Short-Term Cash Obligations

     Our short-term contractual cash obligations as of December 31, 2001, were
as follows (in millions):

<Table>
<S>                                                           <C>
Commercial paper............................................        $424
Notes payable...............................................          75
                                                                    ----
                                                                    $499
                                                                    ====
</Table>

     We can borrow up to $1 billion under a commercial paper program. At
December 31, 2001, the weighted average rate on commercial paper outstanding was
3.2%.

     We also have short-term notes payable to banks of $75 million.

  Long-Term Cash Obligations

     Our unsecured notes and debentures consists of third-party debt issued in
the normal course of our business activities. These notes are secured by our
general credit and that of our subsidiaries. The interest rates on these
instruments range from 6.0% to 10.0%, and maturity dates range from 2002 to
2037. As of December 31, 2001, our total commitments under our long-term cash
obligations were $1,643 million.

                                        24
<PAGE>

  Minority Interests

     Total amounts outstanding under minority interests at December 31, 2001,
were as follows (in millions):

<Table>
<S>                                                           <C>
Gemstone....................................................        $300
Other.......................................................          56
                                                                    ----
                                                                    $356
                                                                    ====
</Table>

     Gemstone. As part of the Gemstone transaction, our wholly owned subsidiary,
Topaz Investors, L.L.C., issued a minority member interest to the third party
investor of Gemstone for $300 million. The third party investor is entitled to a
cumulative preferred return of 8.03% on its interest. The agreements underlying
this transaction expire in 2004, or earlier if we sell the international power
assets owned indirectly by Topaz. The minority member interest is redeemable at
liquidation value plus accrued and unpaid dividends.

  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 2053. As of December 31, 2001, our total commitments under operating
leases were approximately $24 million.

     We have provided a residual value guaranty related to our Chaco plant
lease. 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 guaranty, we would be obligated for the
shortfall. The levels of our residual value guaranty is 87 percent of the
original cost of the leased asset. For the total outstanding residual value
guaranty on our operating lease at December 31, 2001, see Residual Value
Guaranty below.

  Capital Commitments and Purchase Obligations

     At December 31, 2001, we had capital and investment commitments of $1.5
billion primarily relating to our pipeline and international power activities.
Our other planned capital and investment projects are discretionary in nature,
with no substantial capital commitments made in advance of the actual
expenditures. We have entered into unconditional purchase obligations for
products and services including financing commitments with one of our joint
ventures, totaling $157 million at December 31, 2001. Our annual obligations
under these agreements are $28 million for 2002, $25 million for 2003, $27
million for 2004 and 2005, $20 million for 2006 and $30 million in total
thereafter.

COMMERCIAL COMMITMENTS

     From May to October 2001, we entered into agreements to time-charter four
separate ships to secure transportation for our developing liquefied natural gas
business. The agreements provide for deliveries of vessels between 2003 and
2005. Each time-charter has a 20-year term commencing when the vessels are
delivered with the possibility of two 5-year extensions. The total commitment
under the four time charter agreements is $1.8 billion. We do not have any
commitments under these agreements until 2003. Our annual commitments under
these agreements are $7 million in 2003, $37 million in 2004, $72 million in
2005, $89 million in 2006 and $1,574 million in total thereafter.

  Residual Value Guaranty

     As of December 31, 2001, we had a residual value guaranty related to an
operating lease of $77 million. The lease expires in 2002.

                                        25
<PAGE>

                                 CONTINGENCIES

     For a discussion of our contingencies, see Item 8, Financial Statements and
Supplementary Data, Note 10, incorporated herein by reference.

                          CRITICAL ACCOUNTING POLICIES

     The selection and application of accounting policies is an important
process that has developed as our business activities have evolved and as the
accounting rules have developed. Accounting rules generally do not involve a
selection among alternatives, but involve an implementation and interpretation
of existing rules and the use of judgment to the specific set of circumstances
existing in our business. We make every effort to properly comply with all
applicable rules on or before their adoption, and we believe the proper
implementation and consistent application of the accounting rules is critical.
However, not all situations are specifically addressed in the accounting
literature. In these cases, we must use our best judgment to adopt a policy for
accounting for these situations. We accomplish this by analogizing to similar
situations and the accounting guidance governing them, and often consult with
our independent accountants about the appropriate interpretation and application
of these policies. Our critical accounting policies include policies such as
accounting for price risk management activities, accounting for impairments,
accounting for reserves and consolidation policies. Each of these areas involves
complex situations and a high degree of judgment either in the application and
interpretation of existing literature or in the development of estimates that
impact our financial statements.

  Critical Accounting Policies

     Price Risk Management Activities.  We account for price risk management
activities based upon the fair value accounting methods prescribed by Emerging
Issues Task Force (EITF) Issue 98-10 and SFAS No. 133. EITF Issue 98-10 governs
the accounting for our energy trading activities while SFAS No. 133 prescribes
our accounting for hedging activities and other derivatives. Both sets of
accounting rules require that we determine the fair value of the instruments we
use in our business activities and reflect them in our balance sheet at their
fair values. However, changes in the fair value from period to period for our
energy trading derivatives and fair value hedges are recorded in our income
statement each period while changes in the fair value of our cash flow hedges
are generally recognized in our income statement when the hedge is settled. Over
time, these two methods will derive similar results. However, from period to
period, income under these methods can differ significantly.

     One of the primary factors that can have an impact on our results each
period is the price assumptions used to value our energy trading derivatives and
fair value hedges. Many of these instruments have quoted market prices. However,
we are required to use internal valuation techniques or models, particularly in
our energy trading activities, to estimate the fair value of instruments that
are not traded on an active exchange or that have terms that extend beyond the
time period for which exchange-based quotes are available. These modeling
techniques require us to estimate future prices, price correlation, interest
rates and market volatility and liquidity. Our estimates also reflect the
potential impact of liquidating our position in an orderly manner over a
reasonable period of time under present market conditions, modeling risk, credit
risk of our counterparties and operational risk. The amounts we report in our
financial statements change as these estimates are revised to reflect actual
results, changes in market conditions or other factors, many of which are beyond
our control.

     Another factor that can impact our results each period is our ability to
estimate the level of correlation between future changes in the fair value of
the hedge instrument and the transaction being hedged, both at the inception and
on an on-going basis. This is complicated since energy commodity prices, the
primary risk we hedge, have quality and locational differences that can be
difficult to hedge effectively. The factors underlying our estimates of fair
value and our assessment of correlation of our hedging derivatives are impacted
by actual results and changes in conditions that affect these factors, many of
which are beyond of our control.

                                        26
<PAGE>

     Asset Impairments.  The asset impairment accounting rules require us to
determine if an event has occurred indicating that a long-lived asset may be
impaired. In some cases, these events are clear. However, in many cases, a
clearly identifiable triggering event does not occur. Rather, a series of
individually insignificant events occur over a period of time leading to an
indication that an asset may be impaired. This can be further complicated where
we have investments in foreign countries or where we have projects where we are
not the operator. Events can occur that may not be known until a later date from
their occurrence. We continually monitor our businesses and the market and
business environments and make judgments and assessments about whether a
triggering event has occurred. If an event occurs, we make an estimate of our
future cash flows from these assets to determine if the asset is impaired. For
investments, we evaluate whether events and possible outcomes indicate that a
decline in the value of our investment that is other than temporary has
occurred, which also generally involves an assessment of project level cash
flows. These cash flow estimates require us to make projections and assumptions
for many years into the future for pricing, demand, competition, operating
costs, legal and regulatory issues and other factors and these variables can,
and often do, differ from our estimates. These changes can have either a
positive or negative impact on our estimates of impairment and can result in
additional charges. In addition, further changes in the economic and business
environment can impact our original and ongoing assessments of potential
impairment.

     Accounting for Reserves.  Our accounting policies for reserves cover a wide
variety of business activities, including reserves for potentially uncollectible
receivables, rate matters and legal and environmental exposures. We accrue these
reserves when our assessments indicate that it is probable that a liability has
been incurred or an asset will not be recovered, and an amount can be reasonably
estimated. Our estimates for these liabilities are based on currently available
facts and our estimates of the ultimate outcome or resolution of the liability
in the future. Actual results may differ from our estimates, and our estimates
can be, and often are, revised in the future, either negatively or positively,
depending upon the outcome or expectations based on the facts surrounding each
exposure.

     Principles of Consolidation.  We currently have interests in joint
ventures, equity investments and financing arrangements that, based on existing
accounting guidance, we are precluded from consolidating. In December 2001,
Enron Corp., one of the largest companies in the energy industry, declared
bankruptcy in what has been viewed as one of the largest bankruptcies in
history. In the wake of this event, accounting standard setters, including the
Securities and Exchange Commission, are evaluating the existing accounting and
disclosure rules and requirements. One area that has received a high level of
scrutiny is the accounting rules related to consolidations, specifically those
that address special-purpose entities. Standard setting bodies and regulators
are currently evaluating the consolidation rules to determine whether the
existing accounting framework should change. In the future, there is risk that
existing standards will change, particularly in light of the events of 2001, and
that these changes could result in the consolidation in our financial statements
of entities that we do not currently consolidate.

     For further details on these and our other significant accounting policies,
and the estimates, assumptions and judgments we use in applying these policies,
see Item 8, Financial Statements and Supplementary Data, Note 1.

  New Accounting Policies Issued But not Yet Adopted

     Business Combinations.  In July 2001, the Financial Accounting Standards
Board (FASB) issued SFAS No. 141, Business Combinations. This Statement requires
that all transactions that fit the definition of a business combination be
accounted for using the purchase method and prohibits the use of the pooling of
interests method for all business combinations initiated after June 30, 2001.
This Statement also establishes specific criteria for the recognition of
intangible assets separately from goodwill and requires unallocated negative
goodwill to be written off at the acquisition date as an extraordinary item. The
accounting for any business combinations we undertake in the future will be
impacted by this standard. The Statement also requires, upon adoption, that we
write off to income any negative goodwill recognized on business combinations
for which the acquisition date was before July 1, 2001, as the effect of a
change in accounting principle. We do not expect the negative goodwill
provisions of this pronouncement will have a material effect on our financial
statements.

                                        27
<PAGE>

  Goodwill and Other Intangible Assets. In July 2001, the FASB issued SFAS No.
142, Goodwill and Other Intangible Assets. This Statement requires that goodwill
no longer be amortized but periodically tested for impairment at least on an
annual basis. An intangible asset with an indefinite useful life can no longer
be amortized until its useful life becomes determinable. This Statement has
various effective dates, the most significant of which is January 1, 2002. Upon
adoption of this Statement on January 1, 2002, we will no longer recognize
annual amortization expense of approximately $15 million on goodwill and
indefinite-lived intangible assets. We do not expect the impairment provisions
of this pronouncement will have a material effect on our financial statements.

  Accounting for Asset Retirement Obligations. In August 2001, the FASB issued
SFAS No. 143, Accounting for Asset Retirement Obligations. This Statement
requires companies to record a liability relating to the retirement and removal
of assets used in their business. The liability is discounted to its present
value, and the related asset value is increased by the amount of the resulting
liability. Over the life of the asset, the liability will be accreted to its
future value and eventually extinguished when the asset is taken out of service.
The provisions of this Statement are effective for fiscal years beginning after
June 15, 2002. We are currently evaluating the effects of this pronouncement.

  Accounting for the Impairment or Disposal of Long-Lived Assets. In October
2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of
Long-Lived Assets. This Statement requires that long-lived assets that are to be
disposed of by sale be measured at the lower of book value or fair value less
cost to sell. The standard also expanded the scope of discontinued operations to
include all components of an entity with operations that can be distinguished
from the rest of the entity and that will be eliminated from the ongoing
operations of the entity in a disposal transaction. The provisions of this
Statement are effective for fiscal years beginning after December 15, 2001. The
provisions of this Statement will impact any asset dispositions we make after
January 1, 2002, including the announced sale of midstream assets to El Paso
Energy Partners.

  Derivatives Implementation Group Issue C-16. In September 2001, the
Derivatives Implementation Group of the FASB cleared guidance on Issue C-16,
Scope Exceptions: Applying the Normal Purchases and Normal Sales Exception to
Contracts that Combine a Forward Contract and a Purchased Option Contract. This
guidance impacts the accounting for fuel supply contracts that require delivery
of a contractual minimum quantity of a fuel other than electricity at a fixed
price and have an option that permits the holder to take specified additional
amounts of fuel at the same fixed price at various times. We use fuel supply
contracts such as these in our power producing operations and currently do not
reflect them in our balance sheet since they are considered normal purchases
that are not classified as derivative instruments under SFAS No. 133. This
guidance becomes effective in the second quarter of 2002, and we will be
required to account for these contracts as derivative instruments under SFAS No.
133. We are currently evaluating the impact of this guidance on our financial
statements.

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

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

                                        28
<PAGE>

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

     During 2001, we experienced a significantly changing energy market brought
about by the energy crisis in California, the events of September 11th, the
bankruptcy of Enron Corp., and a significant decline in energy commodity prices.
We limited our market risk exposure during this period of market uncertainty by
continually monitoring our net physical and financial positions and assuming
minimal risk. We expect this continuous monitoring and reduced risk assumption
to continue in the near term.

COMMODITY PRICE RISK

  Trading Price Risk

     Our Merchant Energy segment is exposed to market risks inherent in the
financial instruments it uses for trading energy and energy related commodities.
Merchant Energy records its energy trading activities, including transportation
capacity, tolling agreements and storage contracts at fair value. Changes in
fair value of these activities are reflected in our income statement. Merchant
Energy's policy is to manage commodity price risks through a variety of
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 payments to (or receipts from)
       counterparties based on the difference between a fixed and a variable
       price, or two variable prices, for a commodity;

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

     - other contractual arrangements.

  Non-Trading Price Risk

     Our segments are exposed to a variety of market risks in the normal course
of their business activities. Our Field Services segment has market risks
related to the natural gas and natural gas liquids it retains in its processing
operations. Our Merchant Energy segment has market risks from changing prices of
natural gas between locations on capacity it holds on our pipelines. 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 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.

  Price Risk Management

     Merchant Energy measures the risk in its trading and non-trading commodity
and energy related contracts on a daily basis using a Value-at-Risk model to
determine the maximum potential one-day unfavorable impact on its earnings, due
to normal market movements, and monitors its risk in comparison to established
thresholds. Since 1998, Merchant Energy has used what is known as the
variance-covariance technique of measuring Value-at-Risk. This technique uses
historical price movements and specific, defined mathematical parameters to
estimate the characteristics of and the relationships between components of its
assets and liabilities held for price risk management activities. This method
works well for futures, forwards,

                                        29
<PAGE>

and swaps, but does not completely capture the risk of option positions,
especially for large deviations from current underlying values. For this reason,
Merchant Energy began measuring its Value-at-Risk using a historical simulation
technique in December 2001. This technique fully values positions in every
iteration of the simulation and captures risk from all types of positions,
including options. Merchant Energy also uses other measures to provide
additional assurance that the risks in its commodity and energy related
contracts are being properly monitored on a daily basis, including sensitivity
analysis, stress testing, credit risk management and the establishment of
parameters to monitor and measure risk exposure, highlight unfavorable trends,
and measure performance of the portfolio using applicable risk metrics.

     The following table presents our potential one-day unfavorable impact on
earnings before interest and income taxes as measured by Value-at-Risk for our
trading and non-trading commodity and energy related contracts and is prepared
based on a confidence level of 95 percent and a one-day holding period. The high
and low valuations represent the highest and lowest of the month and values
during 2001. The average valuation represents the average of the 2001 month end
values. Actual losses may exceed those measured by Value-at-Risk using either of
the modeling techniques presented below:

<Table>
<Caption>
                                                               VALUE-AT-RISK
                                                 ------------------------------------------
                                                              2001                   2000
                                                 -------------------------------   --------
VALUE-AT-RISK MODELING TECHNIQUE                 YEAR END   HIGH   LOW   AVERAGE   YEAR END
--------------------------------                 --------   ----   ---   -------   --------
                                                               (IN MILLIONS)
<S>                                              <C>        <C>    <C>   <C>       <C>
Trading Value-at-Risk
  Variance-covariance..........................    $21      $45    $21     $33       $29
  Historical simulation........................    $18
Non-Trading Value-at-Risk
  Variance-covariance..........................    $ 5      $15    $ 3     $ 8        --
  Historical simulation........................    $ 7
Portfolio Value-at-Risk(1)
  Historical simulation........................    $14
</Table>

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

(1) Portfolio Value-at-Risk represents the combined Value-at-Risk for the
    trading and non-trading price risk management activities. The separate
    calculation of Value-at-Risk for trading and non-trading commodity contracts
    ignores the natural correlation that exists between traded and non-traded
    commodity contracts and prices. As a result, the individually determined
    values will be higher than the combined Value-at-Risk in most instances. We
    manage our risks through a portfolio approach that balances both trading and
    non-trading risks.

INTEREST RATE RISK

     Many of our debt-related financial instruments, derivative contracts and
project financing arrangements are sensitive to market fluctuations in interest
rates. From time to time, we manage our exposure to interest rate risk through
the use of non-trading derivative financial instruments, primarily through
interest rate swaps.

     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. As of December 31, 2001, the carrying amounts of short-term
borrowings are representative of fair values because of the short-term maturity
of these

                                        30
<PAGE>

instruments. The fair value of the long-term debt has been estimated based on
quoted market prices for the same or similar issues.

<Table>
<Caption>
                                                             DECEMBER 31, 2001                               DECEMBER 31, 2000
                                    --------------------------------------------------------------------   ---------------------
                                            EXPECTED FISCAL YEAR OF MATURITY OF CARRYING AMOUNTS
                                    --------------------------------------------------------------------   CARRYING
                                    2002   2003    2004   2005   2006   THEREAFTER   TOTAL    FAIR VALUE   AMOUNTS    FAIR VALUE
                                    ----   -----   ----   ----   ----   ----------   ------   ----------   --------   ----------
                                                           (DOLLARS IN MILLIONS)
<S>                                 <C>    <C>     <C>    <C>    <C>    <C>          <C>      <C>          <C>        <C>
LIABILITIES:
Short-term debt -- variable
  rate............................  $499                                             $  499     $  499      $  302      $  302
      Average interest rate.......   3.0%
Long-term debt, including current
  portion -- fixed rate...........  $ 65           $ 31   $ 54            $1,452     $1,602     $1,563      $1,977      $2,004
      Average interest rate.......   8.7%           8.9%   9.1%              7.5%
Long-term debt, including current
  portion -- variable rate........  $  3   $   3   $  3   $  3   $  3     $   14     $   29     $   29      $   --      $   --
      Average interest rate.......   6.3%    4.9%   5.8%   6.1%   6.3%       6.3%
</Table>

FOREIGN CURRENCY EXCHANGE RATE RISK

     Our exposure to foreign currency exchange rates relates to changes in
foreign currency rates on our international power investments and operations,
our foreign trading operations and foreign debt obligations that are not
denominated or adjusted to U.S. dollars. From time to time, we manage this
exposure to changes in foreign currency exchange rates by entering into
derivative financial instruments, principally foreign currency forward purchase
and sale contracts. The following table summarizes the notional amounts, average
settlement rates, and fair value for foreign currency forward purchase and sale
contracts as of December 31, 2001:

<Table>
<Caption>
                                                             NOTIONAL AMOUNT                 FAIR VALUE
                                                               IN FOREIGN       AVERAGE          IN
                                                                CURRENCY       SETTLEMENT   U.S. DOLLARS
                                                              (IN MILLIONS)      RATES      (IN MILLIONS)
                                                             ---------------   ----------   -------------
<S>                <C>                                       <C>               <C>          <C>
Canadian Dollars   Purchase................................        401            .653          $(18)
                   Sell....................................        291            .680            17
                                                                                                ----
                                                                                                $ (1)
                                                                                                ====
</Table>

     The following table summarizes foreign currency forward purchase and sale
contracts by expected maturity dates along with annual anticipated cash flow
impacts as of December 31, 2001:

<Table>
<Caption>
                                                                EXPECTED MATURITY DATES
                                                 -----------------------------------------------------
                                                 2002   2003   2004   2005   2006   THEREAFTER   TOTAL
                                                 ----   ----   ----   ----   ----   ----------   -----
                                                                     (IN MILLIONS)
<S>                <C>                           <C>    <C>    <C>    <C>    <C>    <C>          <C>
Canadian Dollars   Purchase....................  $(11)  $(6)   $(2)   $ --   $ --      $ 1       $(18)
                   Sell........................    10     5      2      --     --       --         17
                                                 ----   ---    ---    ----   ----      ---       ----
                   Net cash flow effect........  $ (1)  $(1)   $--    $ --   $ --      $ 1       $ (1)
                                                 ====   ===    ===    ====   ====      ===       ====
</Table>

                                        31
<PAGE>

EQUITY RISK

     Our Merchant Energy Segment holds investments that expose us to price risk
associated with equity securities markets. We account for these investments
using investment company accounting. As a result, these holdings are measured at
their fair value with changes in fair value recorded in our income statement.
The fair value of these investments are determined based on estimates of amounts
that would be realized if these securities were sold. Below are the fair values
of these holdings at December 31, 2001 and 2000, as well as the impact of a ten
percent increase or decrease in the underlying fair values of these securities
for each period presented:

<Table>
<Caption>
                                                 2001                                   2000
                                 ------------------------------------   ------------------------------------
                                              IMPACT OF    IMPACT OF                 IMPACT OF    IMPACT OF
                                              10 PERCENT   10 PERCENT                10 PERCENT   10 PERCENT
                                 FAIR VALUE    INCREASE     DECREASE    FAIR VALUE    INCREASE     DECREASE
                                 ----------   ----------   ----------   ----------   ----------   ----------
                                                                (IN MILLIONS)
<S>                              <C>          <C>          <C>          <C>          <C>          <C>
Investment funds...............     $13          $ 1          $(1)         $ 7          $ 1          $(1)
Securities.....................      15            2           (2)          54            5           (5)
Other..........................      --           --           --            1           --           --
                                    ---          ---          ---          ---          ---          ---
          Total................     $28          $ 3          $(3)         $62          $ 6          $(6)
                                    ===          ===          ===          ===          ===          ===
</Table>

                                        32
<PAGE>

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                         EL PASO TENNESSEE PIPELINE CO.

                       CONSOLIDATED STATEMENTS OF INCOME
                                 (IN MILLIONS)

<Table>
<Caption>
                                                                 YEAR ENDED DECEMBER 31,
                                                               ----------------------------
                                                                2001       2000       1999
                                                               -------    -------    ------
<S>                                                            <C>        <C>        <C>
Operating revenues..........................................   $32,982    $20,788    $9,670
                                                               -------    -------    ------
Operating expenses
  Cost of natural gas and other products....................    30,791     19,076     8,411
  Operation and maintenance.................................       789        576       577
  Merger-related costs and asset impairments................       108         11        75
  Depreciation, depletion and amortization..................       254        223       247
  Taxes, other than income taxes............................        79         62        62
                                                               -------    -------    ------
                                                                32,021     19,948     9,372
                                                               -------    -------    ------
Operating income............................................       961        840       298
                                                               -------    -------    ------
Other income
  Earnings from unconsolidated affiliates...................       197         61        61
  Net gain on sale of assets................................        --         24        24
  Other, net................................................       139         63        64
                                                               -------    -------    ------
                                                                   336        148       149
                                                               -------    -------    ------
Income before interest, income taxes and other charges......     1,297        988       447
                                                               -------    -------    ------
Non-affiliated interest and debt expense....................       149        142       136
Affiliated interest expense, net............................       155        122        40
Minority interest...........................................         4         --        --
Income taxes................................................       320        242        85
                                                               -------    -------    ------
                                                                   628        506       261
                                                               -------    -------    ------
Income before extraordinary items and cumulative effect of
  accounting change.........................................       669        482       186
Extraordinary items, net of income taxes....................        38         58        --
Cumulative effect of accounting change, net of income
  taxes.....................................................        10         --       (13)
                                                               -------    -------    ------
Net income..................................................   $   717    $   540    $  173
                                                               =======    =======    ======
</Table>

                            See accompanying notes.

                                        33
<PAGE>

                         EL PASO TENNESSEE PIPELINE CO.

                          CONSOLIDATED BALANCE SHEETS
                      (IN MILLIONS, EXCEPT SHARE AMOUNTS)

<Table>
<Caption>
                                                                 DECEMBER 31,
                                                               -----------------
                                                                2001      2000
                                                               -------   -------
<S>                                                            <C>       <C>
                                     ASSETS
Current assets
  Cash and cash equivalents.................................   $   197   $   179
  Accounts and notes receivable, net of allowance of $223 in
     2001 and $100 in 2000
     Customer...............................................     2,723     2,829
     Affiliates.............................................       271       194
     Other..................................................       600       262
  Inventory.................................................        79        84
  Assets from price risk management activities..............     2,529     4,283
  Margin deposits on energy trading activities..............       379       377
  Other.....................................................       318       205
                                                               -------   -------
          Total current assets..............................     7,096     8,413
                                                               -------   -------
Property, plant and equipment, at cost
  Pipelines.................................................     2,824     2,554
  Power facilities..........................................       563       351
  Gathering and processing systems..........................     2,199     2,543
  Other.....................................................        99        96
                                                               -------   -------
                                                                 5,685     5,544
Less accumulated depreciation, depletion and amortization...     1,040       843
                                                               -------   -------
                                                                 4,645     4,701
Additional acquisition costs assigned to utility plant, net
  of accumulated amortization...... ........................     2,271     2,287
                                                               -------   -------
Property, plant and equipment, net..........................     6,916     6,988
                                                               -------   -------
Investments in unconsolidated affiliates....................     2,825     2,008
                                                               -------   -------
Assets from price risk management activities................     2,156     1,638
                                                               -------   -------
Other.......................................................     1,002       418
                                                               -------   -------
          Total assets......................................   $19,995   $19,465
                                                               =======   =======
</Table>

                            See accompanying notes.

                                        34
<PAGE>

                         EL PASO TENNESSEE PIPELINE CO.

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

<Table>
<Caption>
                                                                 DECEMBER 31,
                                                               -----------------
                                                                2001      2000
                                                               -------   -------
<S>                                                            <C>       <C>
                      LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
  Accounts and notes payable
     Trade..................................................   $ 2,927   $ 3,156
     Affiliates.............................................     2,932     3,760
     Other..................................................       308       102
  Short-term borrowings.....................................       567       434
  Liabilities from price risk management activities.........     2,089     2,880
  Margin deposits from customers on energy trading
     activities.............................................       649       353
  Other.....................................................       557       347
                                                               -------   -------
          Total current liabilities.........................    10,029    11,032
                                                               -------   -------
Long-term debt..............................................     1,563     1,845
                                                               -------   -------
Deferred credits and other
  Deferred income taxes.....................................     1,971     1,647
  Liabilities from price risk management activities.........     1,236       898
  Other.....................................................       996       838
                                                               -------   -------
                                                                 4,203     3,383
                                                               -------   -------
Commitments and contingencies
Minority interest...........................................       356        51
                                                               -------   -------
Stockholders' equity
  Preferred stock, 20,000,000 shares authorized; Series A,
     no par; 6,000,000 shares issued; stated at
     liquidation value......................................       300       300
  Common stock, par value $0.01 per share; authorized
     100,000 shares; issued 1,971 shares....................        --        --
  Additional paid-in capital................................     1,973     1,962
  Retained earnings.........................................     1,641       949
  Accumulated other comprehensive income....................       (70)      (57)
                                                               -------   -------
          Total stockholders' equity........................     3,844     3,154
                                                               -------   -------
          Total liabilities and stockholders' equity........   $19,995   $19,465
                                                               =======   =======
</Table>

                            See accompanying notes.

                                        35
<PAGE>

                         EL PASO TENNESSEE PIPELINE CO.

                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                                 (IN MILLIONS)

<Table>
<Caption>
                                                                YEAR ENDED DECEMBER 31,
                                                              ---------------------------
                                                               2001      2000      1999
                                                              -------   -------   -------
<S>                                                           <C>       <C>       <C>
Cash flows from operating activities
  Net income................................................  $   717   $   540   $   173
  Adjustments to reconcile net income to net cash from
     operating activities
     Depreciation, depletion and amortization...............      254       223       247
     Deferred income tax expense............................      309       207        69
     Net gain on the sale of assets.........................       --       (24)      (24)
     Extraordinary items....................................      (59)      (99)       --
     Undistributed earnings of unconsolidated affiliates....      (55)      (21)      (30)
     Non-cash portion of merger-related costs and asset
      impairments...........................................       73        11        75
     Non-cash portion of price risk management activities...     (877)     (443)     (281)
     Cumulative effect of accounting changes................      (17)       --        13
     Other..................................................       (8)       --        --
     Working capital changes, net of non-cash transactions
       Accounts and notes receivable........................    1,047    (2,081)      (35)
       Accounts payable/receivable with affiliates..........      431         9       (41)
       Inventory............................................       28        (8)       (3)
       Change in trading price risk management activities,
        net.................................................    1,565    (1,373)      103
       Accounts payable.....................................   (1,246)    1,982       114
       Change in margin deposits from customers on energy
        trading activities..................................      296       351         2
       Other working capital changes........................      136      (269)      (88)
     Non-working capital changes and other..................     (107)      (30)       31
                                                              -------   -------   -------
          Net cash provided by (used in) operating
            activities......................................    2,487    (1,025)      325
                                                              -------   -------   -------
Cash flows from investing activities
  Additions to property, plant and equipment................     (608)     (471)     (458)
  Additions to investments..................................   (1,002)     (794)     (796)
  Cash paid for acquisitions, net of cash acquired..........     (118)     (368)     (165)
  Net proceeds from the sale of assets......................      109       650        31
  Proceeds from the sale of investments.....................       11       122        33
  Change in cash deposited in escrow related to an equity
     investee...............................................        3        24      (101)
  Repayment of notes receivable from unconsolidated
     affiliates.............................................      242        --        --
  Other.....................................................       11       (15)       --
                                                              -------   -------   -------
          Net cash used in investing activities.............   (1,352)     (852)   (1,456)
                                                              -------   -------   -------
Cash flows from financing activities
  Net borrowings (repayments) of commercial paper...........      209      (434)      459
  Payments to retire long-term debt.........................     (384)       (8)       (4)
  Dividends paid............................................      (25)      (25)      (25)
  Net proceeds from the issuance of notes payable...........       --        58       101
  Repayment of notes payable................................       (3)      (82)       --
  Increase (decrease) in notes to unconsolidated
     affiliates.............................................       (9)        9        --
  Net proceeds from issuance of minority interests in
     subsidiaries...........................................      281        --        --
  Net change in other affiliated advances payable...........   (1,186)    2,306       496
  Capital contributions.....................................       --       200       108
                                                              -------   -------   -------
          Net cash provided by (used in) financing
            activities......................................   (1,117)    2,024     1,135
                                                              -------   -------   -------
Increase in cash and cash equivalents.......................       18       147         4
Cash and cash equivalents
  Beginning of period.......................................      179        32        28
                                                              -------   -------   -------
  End of period.............................................  $   197   $   179   $    32
                                                              =======   =======   =======
</Table>

                            See accompanying notes.

                                        36
<PAGE>

                         EL PASO TENNESSEE PIPELINE CO.

                CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
                                 (IN MILLIONS)

<Table>
<Caption>
                                                        FOR THE YEARS ENDED DECEMBER 31,
                                               ---------------------------------------------------
                                                    2001              2000              1999
                                               ---------------   ---------------   ---------------
                                               SHARES   AMOUNT   SHARES   AMOUNT   SHARES   AMOUNT
                                               ------   ------   ------   ------   ------   ------
<S>                                            <C>      <C>      <C>      <C>      <C>      <C>
Series A Preferred Stock.....................     6     $  300      6     $  300      6     $  300
                                                ---     ------    ---     ------     --     ------
Common stock.................................    --         --     --         --     --         --
                                                ---     ------    ---     ------     --     ------
Additional paid-in capital
  Balance at beginning of year...............            1,962             1,707             1,580
  Capital contributions......................               --               233               120
  Allocated tax benefit of El Paso's equity
     plans...................................                9                22                 7
  Proceeds from Encap earnout................                2                --                --
                                                        ------            ------            ------
     Balance at end of year..................            1,973             1,962             1,707
                                                        ------            ------            ------
Retained earnings
  Balance at beginning of year...............              949               451               306
  Net income.................................              717               540               173
  Dividends to parent........................               --               (18)               (1)
  Preferred dividends........................              (25)              (25)              (25)
  Other......................................               --                 1                (2)
                                                        ------            ------            ------
     Balance at end of year..................            1,641               949               451
                                                        ------            ------            ------
Accumulated other comprehensive income
  Balance at beginning of year...............              (57)              (28)              (14)
  Other comprehensive income.................              (13)              (29)              (14)
                                                        ------            ------            ------
     Balance at end of year..................              (70)              (57)              (28)
                                                ---     ------    ---     ------     --     ------
Total stockholders' equity...................     6     $3,844      6     $3,154      6     $2,430
                                                ===     ======    ===     ======     ==     ======
</Table>

                            See accompanying notes.

                                        37
<PAGE>

                       EL PASO TENNESSEE PIPELINE COMPANY

           CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
             AND CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME
                                 (IN MILLIONS)

<Table>
<Caption>
                                                               YEAR ENDED DECEMBER 31,
                                                              -------------------------
                                                               2001      2000     1999
COMPREHENSIVE INCOME                                          -------   ------   ------
<S>                                                           <C>       <C>      <C>
Net income..................................................   $ 717     $540     $173
                                                               -----     ----     ----
  Foreign currency translation adjustments..................      (3)     (29)     (14)
  Unrealized net gains (losses) from cash flow hedging
     activity
     Cumulative-effect transition adjustment (net of tax of
      $66)..................................................    (154)      --       --
     Reclassification of initial cumulative-effect
      transition adjustment at original value (net of tax of
      $66)..................................................     132       --       --
     Additional reclassification adjustments for changes in
      initial value to settlement date (net of tax of
      $45)..................................................      60       --       --
     Unrealized mark-to-market losses arising during period
      (net of tax of $38)...................................     (48)      --       --
                                                               -----     ----     ----
          Other comprehensive income........................     (13)     (29)     (14)
                                                               -----     ----     ----
Comprehensive income........................................   $ 704     $511     $159
                                                               =====     ====     ====
</Table>

<Table>
<Caption>
                                                              2001    2000   1999
ACCUMULATED OTHER COMPREHENSIVE INCOME                        -----   ----   ----
<S>                                                           <C>     <C>    <C>
Beginning balances as of January 1..........................  $ (57)  $(28)  $(14)
  Foreign currency translation adjustments..................     (3)   (29)   (14)
  Unrealized net (losses) from cash flow hedging activity
     Cumulative-effect transition adjustment, net of
      taxes.................................................   (154)    --     --
     Reclassification of initial cumulative-effect
      transition adjustment at original value, (net of
      taxes)................................................    132     --     --
     Additional reclassification adjustments for changes in
      initial value to settlement date, net of taxes........     60     --     --
     Unrealized mark-to-market losses arising during period
      net of taxes..........................................    (48)    --     --
                                                              -----   ----   ----
Balance as of December 31,..................................  $ (70)  $(57)  $(28)
                                                              =====   ====   ====
</Table>

                            See accompanying notes.

                                        38
<PAGE>

                         EL PASO TENNESSEE PIPELINE CO.

                   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 had no impact on reported net income or
stockholders' 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.

  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 interstate natural gas systems and storage operations are subject to
the jurisdiction of FERC in accordance with the Natural Gas Act of 1938 and the
Natural Gas Policy Act of 1978. Our regulated operations apply the provisions of
Statement of Financial Accounting Standards No. 71, Accounting for the Effects
of Certain Types of Regulation. Accounting for businesses that are regulated and
apply the provisions of SFAS No. 71 can differ from the accounting requirements
for non-regulated businesses. Transactions that have been recorded differently
as a result of regulatory accounting requirements include the capitalization of
an equity return component on regulated capital projects, employee related
benefits, and other costs and taxes included in, or expected to be included in,
future rates.

     We will continue to evaluate the application of regulatory accounting
principles as there are on-going changes in the regulatory and economic
environment. Things that may influence this assessment are:

     - inability to recover cost increases due to rate caps and rate case
       moratoriums;

     - inability to recover capitalized costs, including an adequate return on
       those costs through the ratemaking process;

     - excess capacity;

     - discounting rates in the markets we serve; and

     - impacts of ongoing initiatives in, and deregulation of, the natural gas
       industry.

  Cash and Cash Equivalents

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

                                        39
<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 materials and supplies and natural gas in storage
for non-trading purposes. We value all inventory at the lower of cost or market
with cost determined using the average cost method.

  Natural Gas Imbalances

     Natural gas imbalances occur when the actual amount of natural gas
delivered from or received by a pipeline system, processing plant or storage
facility differs from the contractual amount scheduled to be delivered or
received. We value these gas imbalances due to or from shippers and operators at
an appropriate market index price based on when we expect to settle the
imbalance. Imbalances are settled in cash or made up in-kind, subject to the
contractual terms of settlement.

     Imbalances due from others are reported in our balance sheet as either
accounts receivable from customers or accounts receivable from affiliates.
Imbalances owed to others are reported on the balance sheet as either trade
accounts payable or accounts payable to affiliates. In addition, all imbalances
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, interest and in our regulated businesses, an equity return
component. We capitalize the major units of property replacements or
improvements and expense minor items. Included in our pipeline property balances
are additional acquisition costs which represent the excess purchase costs
associated with purchase business combinations allocated to our regulated
interstate systems. These costs are amortized on a straight-line basis, and we
do not recover these excess costs in our rates.

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

<Table>
<Caption>
                                                            REMAINING
                  TYPE                        METHOD       USEFUL LIVES     RATES
-----------------------------------------  -------------   ------------   ----------
                                                            (IN YEARS)
<S>                                        <C>             <C>            <C>
Regulated systems(1).....................    Composite       2-33          1% to 24%
Non-regulated systems
  Gathering and processing systems.......  Straight-line     1-40          3% to 40%
  Power facilities.......................  Straight-line     1-49          2% to 33%
  Transportation equipment...............  Straight-line      1-5         20% to 33%
  Buildings and improvements.............  Straight-line     1-40          3% to 20%
  Office and miscellaneous equipment.....  Straight-line     1-10         10% to 50%
</Table>

(1) We use the composite (group) method to depreciate regulated property, plant
    and equipment. Under this method, assets with similar lives and other
    characteristics are grouped and depreciated as one asset. We apply the
    depreciation rate approved in our tariff, to the total cost of the group,
    until its net book value equals its salvage value. We reevaluate
    depreciation rates each time we redevelop our transportation rates when we
    file with FERC for an increase or decrease in rates.

     When we retire regulated property, plant and equipment, we charge
accumulated depreciation and amortization for the original cost, plus the cost
of retirement (the cost to remove, sell or dispose), less its salvage value. We
do not recognize a gain or loss unless we sell an entire operating unit. We
include gains or

                                        40
<PAGE>

losses on dispositions of operating units in income. When we retire
non-regulated properties, we reduce property, plant and equipment for its
original cost, less accumulated depreciation, and salvage. Any remaining gain or
loss is recorded in income.

     At December 31, 2001 and 2000, we had approximately $347 million and $343
million of construction work in progress included in our property, plant and
equipment.

  Asset Impairments

     We evaluate our long-lived assets for impairments in accordance with SFAS
No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of. If an adverse event or change in circumstances occurs,
we estimate the future cash flows from the asset, grouped together at the lowest
level for which separate cash flows can be measured, to determine if the asset
is impaired. If the total of the undiscounted future cash flows is less than the
carrying amount for the assets, we calculate the fair value of the assets either
through reference to sales data for similar assets, or by estimating the fair
value using a discounted cash flow approach. These cash flow estimates require
us to make estimates and assumptions for many years into the future for pricing,
demand, competition, prices, operating costs, legal, regulatory and other
factors, and these assumptions can change either positively or negatively.

  Intangible Assets

     Intangible assets consist primarily of goodwill arising as a result of
mergers and acquisitions. We amortize these intangible assets using the
straight-line method over periods ranging from 5 to 40 years. We evaluate
impairment of goodwill in accordance with APB No. 17, Intangible Assets, as
amended by SFAS No. 121. Under this methodology, when an event occurs that
suggests that an impairment may have occurred, we evaluate the undiscounted net
cash flows of the asset or entity to which the goodwill relates. If these cash
flows are not sufficient to recover the value of the asset or entity plus its
related goodwill, these cash flows are discounted at a risk-adjusted rate with
any difference recorded as a change in our income statement.

  Revenue Recognition

     Our regulated businesses recognize revenues from natural gas transportation
services and services other than transportation in the period when the service
is provided. In the future, we will record reserves on revenues collected that
may be subject to refund.

     Our non-regulated businesses record revenues when they are earned. Revenues
are earned when deliveries of physical commodities are made, or when services
are provided. See the discussion of price risk management activities below for
our revenue recognition policies on our trading activities.

  Environmental Costs and Other Contingencies

     We expense or capitalize expenditures for ongoing compliance with
environmental regulations that relate to past or current operations as
appropriate. We expense amounts for clean up of existing environmental
contamination caused by past operations which do not benefit future periods by
preventing or eliminating future contamination. We record liabilities when our
environmental assessments indicate that remediation efforts are probable, and
the costs can be reasonably estimated. Estimates of our liabilities are based on
currently available facts, existing technology and presently enacted laws and
regulations taking into consideration the likely effects of 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 Environmental
Protection Agency (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,
government sponsored and other 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.

                                        41
<PAGE>

     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 for both trading and
non-trading purposes to manage market risks associated with commodities we
purchase and sell, interest rates and foreign currency exchange rates.

     Our trading and non-trading price risk management activities involve the
use of a variety of derivative financial instruments, including:

     - exchange-traded futures contracts that involve cash settlements;

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

     - swap contracts, which 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.

     Trading Activities.  Our trading activities include the services we provide
in the energy sector, primarily related to the purchase and sale of energy
commodities. We account for our trading activities at their fair market value
under the requirements of Emerging Issues Task Force (EITF) Issue 98-10,
Accounting for Contracts Involved in Energy Trading and Risk Management
Activities. In addition to the derivatives above, our trading activities also
include non-derivative instruments such as transportation and storage capacity
contracts, and physical natural gas that is actively traded. We reflect the
market values of our trading activities in our balance sheet as price risk
management activities. These are classified as current or long-term based on
their anticipated settlement date. In our income statement, we account for
physical settlements that result in delivery of a commodity as revenues or cost
of products sold based on whether we buy or sell the commodity. Financial
settlements as well as changes in the market value of traded positions are
included in revenue.

     Non-trading Activities.  Our non-trading price risk management activities
involve the use of derivative financial instruments to hedge the impact of
market price risk exposures on our assets, liabilities, contractual commitments
and forecasted transactions related to our gas transmission, power generation,
financing and international business activities. On January 1, 2001, we adopted
the provisions of SFAS No. 133, Accounting for Derivative Instruments and
Hedging Activities, in accounting for our non-trading derivative instruments.
Under SFAS No. 133, all derivatives are reflected in our balance sheet at their
fair market value. We do not apply the mark-to-market method of accounting for
contracts that qualify as normal purchases and sales under SFAS No. 133.

     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 a 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 the 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

                                        42
<PAGE>

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.

     The market value of both trading and non-trading instruments reflects our
best estimate and is based upon exchange or over-the-counter quotations whenever
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 our 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 estimates 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 period of time under present market conditions,
modeling risk, credit risk of our counterparties and operational risk. Our
actual results may differ from our estimates, and these differences can be
positive or negative.

     Cash inflows and outflows associated with the settlement of both trading
and non-trading 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.

     Prior to our adoption of SFAS No. 133, we applied hedge accounting for our
non-trading derivatives only if the derivative reduced the risk of the
underlying hedged item, was designated as a hedge at its inception and was
expected to result in financial impacts which were inversely correlated to those
of the item being hedged. If correlation ceased to exist, hedge accounting was
terminated and the derivatives were recorded at their fair value in the balance
sheet and changes in fair value were recorded in income. Changes in the market
value of derivatives designated as hedges were deferred as deferred revenue or
expense until the gain or loss was recognized on the hedged transaction.
Derivatives held for non-trading purposes were recorded as gains or losses in
operating income and cash inflows and outflows were recognized in operating cash
flow as the settlement of those transactions occurred.

  Income Taxes

     We report current income taxes based on our taxable income along with a
provision for deferred income taxes. Deferred income taxes reflect the estimated
future tax consequences 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 the 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 sharing policy for companies included in its
consolidated federal income tax return which provides, among other things, that
(i) each company in a taxable income position will be currently charged with an
amount equivalent to its federal income tax computed on a separate return basis,
and (ii) each company in a tax loss position will be reimbursed currently to the
extent its deductions, including general business credits, were utilized in the
consolidated return. Under the policy, El Paso pays all federal income taxes
directly to the IRS and bills or refunds its subsidiaries, including us, for
their portion of these income tax payments.

  Foreign Currency Transactions and Translation

     We record all currency transaction gains and losses in income. The net
currency transaction loss recorded to income in 2001 was $10 million and was
insignificant in 2000. The U.S. dollar is the functional currency for
substantially all of our foreign operations. For foreign operations whose
functional currency is deemed to be

                                        43
<PAGE>

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 $60 million and $57 million at
December 31, 2001 and 2000. Revenues and expenses are translated at average
exchange rates prevailing during the year.

  Cumulative Effect of Accounting Change

     In November 2001, the Financial Accounting Standards Board (FASB) issued
EITF Issues Topic D-105 (D-105), Accounting in Consolidation for Energy Trading
Contracts between Affiliated Entities When the Activities of One but Not Both
Affiliates Are within the Scope of EITF Issue No. 98-10, "Accounting for
Contracts Involved in Energy Trading and Risk Management Activities". This
announcement requires all energy trading transactions, and any related
mark-to-market gains and losses, between entities of the same consolidated group
to be eliminated in consolidated financial statements. It also requires energy
trading transactions with these affiliated companies to be reflected in the
stand-alone financial statements of the energy-trading entities involved in
these transactions. We adopted the announcement effective December 31, 2001, and
reported a gain of $10 million, net of income taxes of $7 million, related to
our contracts with non-EITF Issue No. 98-10 affiliates. We recorded this amount
as a cumulative effect of an accounting change in accordance with the transition
provisions of D-105.

     In April 1998, the American Institute of Certified Public Accountants
issued Statement of Position 98-5, Reporting on the Costs of Start-Up
Activities. The statement defined start-up activities and required start-up and
organization costs be expensed as incurred. In addition, it required that any
such cost that existed on the balance sheet be expensed upon adoption of the
pronouncement. We adopted the pronouncement effective January 1, 1999, and
reported a charge of $13 million, net of income taxes, as a cumulative effect of
accounting change.

  New Accounting Pronouncements Issued But Not Yet Adopted

     During 2001, the Financial Accounting Standards Board issued SFAS No. 141,
Business Combinations, SFAS No. 142 Goodwill and Other Intangible Assets, SFAS
No. 143, Accounting for Asset Retirement Obligations and SFAS No. 144,
Accounting for the Impairment or Disposal of Long-Lived Assets. Each of these
standards has a required adoption date of January 1, 2002, except SFAS No. 143,
which is required to be adopted in 2003. SFAS No. 141 will impact the manner in
which we account for business combinations. SFAS No. 142 will impact the manner
in which we account for goodwill and test goodwill for impairment. SFAS No. 143
will impact the accruals we make to retire or remove long-lived assets. SFAS No.
144 will impact how we account for asset impairments and the accounting for
discontinued operations.

2. ACQUISITIONS AND DIVESTITURES

  Texas Midstream Operations

     In December 2000, we completed our purchase of Pacific Gas & Electric's
(PG&E's) Texas Midstream operations. The total value of the transaction was $887
million, including assumed debt of approximately $527 million. The transaction
was accounted for as a purchase and is included in our Field Services segment.

     The operations acquired consisted of 7,500 miles of intrastate natural gas
transmission and natural gas liquids pipelines that transport approximately 2.8
Bcf/d, nine natural gas processing and fractionation plants that currently
process 1.5 Bcf/d, and rights to 7.2 Bcf of natural gas storage capacity. In
March 2001, we sold some of these acquired natural gas liquids transportation
and several fractionation assets to El Paso Energy Partners for approximately
$133 million.

  Divestitures

     During 2000, we sold East Tennessee Natural Gas Company to comply with a
FTC order related to El Paso's merger with Sonat. This merger was accounted for
by El Paso as a pooling of interests. Net proceeds from the sale were
approximately $386 million and we recognized an extraordinary gain of $77
million, net of

                                        44
<PAGE>

income taxes of $51 million. Our treatment of this gain as an extraordinary item
was consistent with that of our parent company, El Paso. In December 2000, we
sold our interest in Oasis Pipeline Company to comply with a FTC order related
to our acquisition of PG&E's Texas Midstream assets. We incurred a loss on this
transaction of approximately $19 million, net of income taxes of $10 million. We
recorded the gains and losses on these sales as extraordinary items in our
income statement. This treatment was consistent with that of El Paso.

     As a result of El Paso's merger with The Coastal Corporation, we were
required by the FTC to sell our Midwestern Gas Transmission system. We completed
this sale in April 2001. Net proceeds were approximately $95 million, and we
recognized an extraordinary gain of $38 million, net of income taxes of $21
million. Additionally, El Paso Energy Partners sold its interests in several
offshore assets under a FTC order related to El Paso's merger with Coastal.
These sales resulted in a $25 million loss to the partnership. As consideration
for these sales, we committed to pay El Paso Energy Partners a series of
payments totaling $29 million. These payments were recorded as merger-related
costs.

     In February 2002, El Paso announced the sale of several of our midstream
assets to El Paso Energy Partners for total consideration of $750 million. The
assets to be sold include:

     - 9,400 miles of intrastate transmission pipelines;

     - 1,300 miles of gathering systems in the Permian Basin; and

     - a 42.3 percent non-operating interest in the Indian Basin gas processing
       and treating plant and associated gathering lines.

3. MERGER-RELATED COSTS AND ASSET IMPAIRMENT CHARGES

     During each of the three years ended December 31, we recorded
merger-related costs associated with El Paso's mergers with Coastal and Sonat.
These mergers were accounted for as a pooling of interests and asset impairment
charges, as follows:

<Table>
<Caption>
                                                              YEAR ENDED DECEMBER 31,
                                                              -----------------------
                                                              2001     2000     1999
                                                              -----    -----    -----
                                                                   (IN MILLIONS)
<S>                                                           <C>      <C>      <C>
Merger-related costs........................................  $ 35      $--      $72
Asset impairments...........................................    73       11        3
                                                              ----      ---      ---
                                                              $108      $11      $75
                                                              ====      ===      ===
</Table>

     Merger-Related Costs. Our merger-related costs relate to El Paso's mergers
with Coastal and Sonat and consisted of the following:

<Table>
<Caption>
                                                              YEAR ENDED DECEMBER 31,
                                                              -----------------------
                                                              2001     2000     1999
                                                              -----    -----    -----
                                                                   (IN MILLIONS)
<S>                                                           <C>      <C>      <C>
Employee severance, retention and transition costs..........  $  6     $ --     $ --
Merger-related asset impairments............................    --       --       63
Other.......................................................    29       --        9
                                                              ----     ----     ----
                                                              $ 35       --     $ 72
                                                              ====     ====     ====
</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 El Paso's merger-related workforce reduction and consolidation.
These costs were expensed as incurred and have been paid. Other consists of
make-whole commitments related to a series of payments we will make to El Paso
Energy Partners in connection with the FTC's ordered divestiture of interests in
assets owned by the partnership in connection with the Coastal merger and other
miscellaneous charges. These will be paid quarterly through 2003.

                                        45
<PAGE>

     Asset Impairments. The 2001 asset impairment charges resulted from the
write-downs of our investments in several international power projects in our
Merchant Energy segment. The 2000 charges consisted of the impairment of a
domestic gas processing facility in our Field Services segment. The 1999 charge
consisted of discontinued capital projects. The impairments in these periods
were primarily a result of weak or changing economic conditions causing
permanent declines in the value of these assets, and the charges taken for all
assets were based on a comparison of each asset's carrying value to its
estimated fair value based on future estimated cash flows. These assets continue
to be held for use, or their operations have been suspended.

4. INCOME TAXES

     Pretax income 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>
                                                              2001     2000     1999
                                                              ----     ----     ----
                                                                  (IN MILLIONS)
<S>                                                           <C>      <C>      <C>
United States...............................................  $960     $660     $215
Foreign.....................................................    29       64       56
                                                              ----     ----     ----
                                                              $989     $724     $271
                                                              ====     ====     ====
</Table>

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

<Table>
<Caption>
                                                              2001     2000     1999
                                                              ----     ----     ----
                                                                  (IN MILLIONS)
<S>                                                           <C>      <C>      <C>
Current
  Federal...................................................  $ (2)    $ (8)    $ 21
  State.....................................................   (11)     (27)     (16)
  Foreign...................................................    23        7       11
                                                              ----     ----     ----
                                                                10      (28)      16
                                                              ----     ----     ----
Deferred
  Federal...................................................   313      234       64
  State.....................................................     8       39        6
  Foreign...................................................   (11)      (3)      (1)
                                                              ----     ----     ----
                                                               310      270       69
                                                              ----     ----     ----
          Total income tax expense..........................  $320     $242     $ 85
                                                              ====     ====     ====
</Table>

                                        46
<PAGE>

     Our income tax expense included in income 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>
                                                              2001   2000   1999
                                                              ----   ----   ----
                                                                (IN MILLIONS)
<S>                                                           <C>    <C>    <C>
Income tax expense at the statutory federal rate of 35%.....  $346   $253   $95
Increase (decrease)
  State income tax, net of federal income tax benefit.......    (2)     8    (7)
  Dividend exclusion........................................    (9)   (11)   (6)
  Non-deductible portion of merger-related costs............    --     --     5
  Foreign income taxed at different rates...................    13    (19)   (4)
  Other.....................................................   (28)    11     2
                                                              ----   ----   ---
Income tax expense..........................................  $320   $242   $85
                                                              ====   ====   ===
Effective tax rate..........................................    32%    33%   31%
                                                              ====   ====   ===
</Table>

     The following are the components of our net deferred tax liability at
December 31:

<Table>
<Caption>
                                                               2001     2000
                                                              ------   ------
                                                               (IN MILLIONS)
<S>                                                           <C>      <C>
Deferred tax liabilities
  Property, plant and equipment.............................  $1,775   $1,884
  Investments in unconsolidated affiliates..................     230      113
  Price risk management activities..........................     475      244
  Other.....................................................     197      138
                                                              ------   ------
          Total deferred tax liability......................   2,677    2,379
                                                              ------   ------
Deferred tax assets
  U.S. net operating loss and tax credit carryovers.........     386      235
  Employee benefit and deferred compensation obligations....      53       78
  Environmental liability...................................      86       71
  Other liabilities.........................................     384      397
  Valuation allowance.......................................      (2)      (2)
                                                              ------   ------
          Total deferred tax asset..........................     907      779
                                                              ------   ------
Net deferred tax liability..................................  $1,770   $1,600
                                                              ======   ======
</Table>

     At December 31, 2001, 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 $212 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 adjustments recorded in other
comprehensive income.

     Under El Paso's tax sharing policy, we are allocated the tax benefit
associated with our employees' exercise of non-qualified stock options and the
vesting of restricted stock as well as restricted stock dividends. This
allocation reduced taxes payable by $9 million in 2001, $22 million in 2000 and
$7 million in 1999. These benefits are included in additional paid-in capital in
our balance sheets.

                                        47
<PAGE>

     As of December 31, 2001, we had alternative minimum tax credits of $23
million that carryover indefinitely. The table presented below details the net
operating loss carryovers periods. Usage of these carryovers is subject to the
limitations provided under Sections 382 and 383 of the Internal Revenue Code as
well as the separate return limitation year rules of the IRS regulations.

<Table>
<Caption>
                                                           CARRYOVER PERIOD
                                   -----------------------------------------------------------------
                                     2002      2003-2010    2011-2015    2016-2020    2021    TOTAL
                                   --------    ---------    ---------    ---------    ----    ------
                                                             (IN MILLIONS)
<S>                                <C>         <C>          <C>          <C>          <C>     <C>
Net operating loss...............     $--         $45         $181         $581       $229    $1,036
</Table>

     We recorded a valuation allowance to reflect the estimated amount of
deferred tax assets which may not be realized due to the expiration of net
operating loss carryovers of an acquired company.

5. FINANCIAL INSTRUMENTS AND PRICE RISK MANAGEMENT ACTIVITIES

  Fair Value of Financial Instruments

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

<Table>
<Caption>
                                                                 2001                    2000
                                                         ---------------------   ---------------------
                                                         CARRYING                CARRYING
                                                          AMOUNT    FAIR VALUE    AMOUNT    FAIR VALUE
                                                         --------   ----------   --------   ----------
                                                                         (IN MILLIONS)
<S>                                                      <C>        <C>          <C>        <C>
Balance sheet financial instruments:
     Investments.......................................   $   28      $   28      $   62     $    62
     Long-term debt, including current maturities......    1,631       1,592       1,977       2,004
     Trading instruments
       Futures contracts...............................     (172)       (172)        137         137
       Option contracts(1).............................      557         557        (118)       (118)
       Swap and forward contracts(1)...................     (103)       (103)      1,150       1,150
Other financial instruments:
     Non-trading instruments(2)
       Commodity swap and forward contracts............   $   23      $   23      $   --     $    --
</Table>

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

(1) Excludes all physical contracts, including transportation capacity, tolling
    agreements and natural gas in storage held for trading purposes since these
    do not constitute financial instruments.

(2) On January 1, 2001, we adopted SFAS No. 133. Under SFAS No. 133, all
    derivative instruments are recorded at their fair value in our financial
    statements.

     As of December 31, 2001 and 2000, 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 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.

                                        48
<PAGE>

     Trading and Non-Trading 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>
                                                               2001       2000
                                                              ------     ------
                                                                (IN MILLIONS)
<S>                                                           <C>        <C>
Trading price risk management activities:
  Futures contracts.........................................  $ (172)    $  137
  Option contracts
     Financial instruments..................................     557       (118)
     Physical contracts(1)..................................     897        659
                                                              ------     ------
       Total option contracts...............................   1,454        541
  Swap and forward contracts
     Financial instruments..................................    (103)     1,150
     Physical contracts(1)..................................     163        304
                                                              ------     ------
       Total swap and forward contracts.....................      60      1,454
  Non-commodity contracts...................................      (5)        11
                                                              ------     ------
          Net assets from trading price risk management
             activities.....................................   1,337      2,143
Non-trading price risk management activities:
  Swap and forward contracts................................      23         --
                                                              ------     ------
          Net assets from non-trading price risk management
             activities.....................................      23         --
                                                              ------     ------
          Net assets from price risk management
             activities.....................................  $1,360     $2,143
                                                              ======     ======
</Table>

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

(1) Physical contracts include transportation capacity, tolling agreements and
    natural gas in storage held for trading purposes.

  Commodity Trading Activities

     We recognized gross margins from our trading activities of $675 million and
$406 million for the year ended December 31, 2001 and 2000. The fair value of
commodity and energy related contracts entered into for trading purposes as of
December 31, 2001 and 2000, and the average fair value of those instruments are
set forth below:

<Table>
<Caption>
                                                                              AVERAGE FAIR
                                                                              VALUE FOR THE
                                                                               YEAR ENDED
                                                    ASSETS    LIABILITIES    DECEMBER 31,(1)
                                                    ------    -----------    ---------------
                                                                 (IN MILLIONS)
<S>                                                 <C>       <C>            <C>
2001
Futures contracts.................................  $   --      $  (172)         $   72
Option contracts..................................   1,822         (368)          1,738
Swap and forward contracts........................   2,838       (2,778)            (43)
2000
Futures contracts.................................  $  137      $    --          $  266
Option contracts..................................   2,134       (1,593)            589
Swap and forward contracts........................   3,639       (2,185)            518
</Table>

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

(1) Computed using the net asset (liability) balance at the end of each month
    end.

                                        49
<PAGE>

  Notional Amounts and Terms of Trading Price Risk Management Activities

     The notional amounts and terms of our energy commodity financial
instruments at December 31, 2001, and 2000 are set forth below:

<Table>
<Caption>
                                                     FIXED PRICE   FIXED PRICE      MAXIMUM
                                                        PAYOR       RECEIVER     TERMS IN YEARS
                                                     -----------   -----------   --------------
<S>                                                  <C>           <C>           <C>
2001
Energy Commodities:
  Natural gas (TBtu)...............................    23,407        23,259            27
  Power (Terawatt Hours)...........................       655           671            19
  Crude oil and refined products (MMBbls)..........        15            20             5
  Weather (thousands of degree days)...............       468           469             2
  Energy capacity (Gigawatt hours).................        33            50            12
  Emissions (MTons)................................       148           178             1
2000
Energy Commodities:
  Natural gas (TBtu)...............................    34,306        29,896            27
  Power (Terawatt Hours)...........................       133           143            20
  Crude oil and refined products (MMBbls)..........         8             8             6
  Weather (thousands of degree days)...............       133           135            --
  Energy capacity (Gigawatt hours).................        22            29             3
</Table>

     The notional amounts included in the table above reflect the contracted
notional volumes multiplied by the number of delivery periods remaining under
the related contracts. These notional amounts are not indicative of future cash
flows as we may decide to sell the contracts into the commodity markets in the
future.

     The notional amount and terms of foreign currency forward purchases and
sales and interest rate swaps and futures at December 31, 2001 and 2000, were as
follows:

<Table>
<Caption>
                                                           NOTIONAL VOLUME
                                                      -------------------------      MAXIMUM
                                                          BUY          SELL       TERM IN YEARS
                                                      -----------   -----------   -------------
<S>                                                   <C>           <C>           <C>

2001
  Foreign Currency (in millions)
     Canadian dollars...............................       401            291             10
  Interest Rates (in millions)
     3-Month LIBOR..................................       145             68             20
2000
  Foreign Currency (in millions)
     Canadian dollars...............................     1,095            441     8 years
     Korean Won.....................................        --        132,500     1 month
     Philippine Peso................................        --          4,392     1 month
</Table>

     The weighted average maturity of our entire portfolio of price risk
management activities was approximately four years as of December 31, 2001, and
two years as of December 31, 2000.

  Market and Credit Risks

     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 these

                                        50
<PAGE>

transactions 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 El Paso's stated risk management policies.

     We measure and adjust the risk in our portfolio 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.

     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 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. The counterparties associated with our
assets from trading price risk management activities are summarized as follows:

<Table>
<Caption>
                                               ASSETS FROM TRADING PRICE RISK MANAGEMENT ACTIVITIES AS
                                                                 OF DECEMBER 31, 2001
                                              ----------------------------------------------------------
                                                                            BELOW
                                              INVESTMENT GRADE(1)   INVESTMENT GRADE(1)(2)   TOTAL(3)(4)
                                              -------------------   ----------------------   -----------
                                                                    (IN MILLIONS)
<S>                                           <C>                   <C>                      <C>
Energy marketers............................        $1,462                   $370              $1,832
Financial institutions......................           189                     --                 189
Oil and natural gas producers...............           693                     13                 706
Natural gas and electric utilities..........         1,291                     83               1,374
Industrials.................................            21                     18                  39
Municipalities..............................           223                     --                 223
Natural gas and electric utilities not
  publicly rated............................            99                      2                 101
                                                    ------                   ----              ------
         Total assets from trading price
           risk management activities.......        $3,978                   $486              $4,464
                                                    ======                   ====              ======
</Table>

<Table>
<Caption>
                                               ASSETS FROM TRADING PRICE RISK MANAGEMENT ACTIVITIES AS
                                                                OF DECEMBER 31, 2000
                                              ---------------------------------------------------------
                                                                            BELOW
                                              INVESTMENT GRADE(1)   INVESTMENT GRADE(1)(2)    TOTAL(3)
                                              -------------------   ----------------------   ----------
                                                                    (IN MILLIONS)
<S>                                           <C>                   <C>                      <C>
Energy marketers............................        $2,461                   $  8              $2,469
Financial institutions......................         1,161                     --               1,161
Oil and natural gas producers...............           613                     --                 613
Natural gas and electric utilities..........         1,496                     54               1,550
Industrials.................................            98                      2                 100
Municipalities..............................            17                     --                  17
Natural gas and electric utilities not
  publicly rated............................            10                      1                  11
                                                    ------                   ----              ------
         Total assets from trading price
           risk management activities.......        $5,856                   $ 65              $5,921
                                                    ======                   ====              ======
</Table>

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

(1)"Investment Grade" and "Below Investment Grade" are primarily determined
   using publicly available credit ratings, or if a counterparty is not publicly
   rated, a minimum implied credit rating through internal credit analysis.
   "Investment Grade" includes counterparties with a minimum Standard & Poor's
   rating of BBB- or Moody's rating of Baa3. "Below Investment Grade" includes
   counterparties with a credit rating that do not meet the criteria of
   "Investment Grade".

(2)As of December 31, 2001, we required collateral, which encompasses margins,
   standby letters of credit, and parent company guarantees, for $375 million of
   the $486 million, or 77%, from counterparties included in "Below Investment
   Grade".

(3)We had one customer that comprised greater than 5 percent of assets from
   price risk management activities as of December 31, 2001. Although this
   customer was considered below investment grade, our position with this
   counterparty was fully collateralized through margins and standby letters of
   credit. We had one customer that comprised greater than 5 percent of assets
   from price risk management activities as of December 31, 2000. The customer
   was considered investment grade.

(4)Counterparty total does not include natural gas in storage or marketable
   securities held for trading purposes of $196 million at December 31, 2001.

                                        51
<PAGE>

     This concentration of counterparties may impact our overall exposure to
credit risk, either positively or negatively, in that the counterparties may be
similarly affected by changes in economic, regulatory or other conditions.

  Non-Trading Price Risk Management Activities

     We also utilize derivative financial instruments for non-trading activities
to mitigate market price risk associated with significant physical transactions.
Non-trading commodity activities are accounted for using hedge accounting
provided they meet hedge accounting criteria. Non-trading activities are
conducted through exchange traded futures contracts, swaps, and forward
agreements with third parties.

     The notional amounts and terms of contracts held for purposes other than
trading were as follows at December 31:

<Table>
<Caption>
                                                         2001                       2000
                                               ------------------------   ------------------------
                                                 NOTIONAL                   NOTIONAL
                                                  VOLUME                     VOLUME
                                               -------------   MAXIMUM    -------------   MAXIMUM
                                               BUY      SELL     TERM     BUY      SELL     TERM
                                               ---      ----   --------   ---      ----   --------
<S>                                            <C>      <C>    <C>        <C>      <C>    <C>
Commodity
  Natural gas (TBtu).........................  16        31    3 months   114      130    5 months
</Table>

     We also face credit risk with respect to our non-trading activities, and
take similar measures as in our trading activities to mitigate this risk. Based
upon our policies and risk exposure, we do not anticipate a material effect on
our financial position, operating results or cash flows resulting from
counterparty non-performance.

6. ACCOUNTING FOR HEDGING ACTIVITIES

     On January 1, 2001, we adopted the provisions of SFAS No. 133 and recorded
a cumulative-effect adjustment of $154 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, $132 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 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, 2001, the value of cash
flow hedges included in accumulated other comprehensive income was a net
unrealized loss of $10 million, net of income taxes. We estimate that unrealized
losses of $2 million will be reclassified from accumulated other comprehensive
income over the next 12 months. Reclassifications occur upon physical delivery
of the hedged commodity and the corresponding expiration of the hedge. The
maximum term of our cash flow hedges is 2 years.

     Our accumulated other comprehensive income includes a loss of $20 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 loss is a $10 million loss that we
estimate will be reclassified from accumulated other comprehensive income over
the next 12 months. The maximum term of these cash flow hedges is 2 years,
excluding hedges relating to interest rates on variable debt.

     For the year ended December 31, 2001, we recognized a net gain of $5
million, net of income taxes, related to the ineffective portion of all cash
flow hedges.

                                        52
<PAGE>

7. INVENTORY

     Our inventory consisted of the following at December 31:

<Table>
<Caption>
                                                              2001     2000
                                                              -----    -----
                                                              (IN MILLIONS)
<S>                                                           <C>      <C>
Natural gas in storage......................................  $ 41     $ 58
Materials and supplies, and other...........................    38       26
                                                              ----     ----
          Total.............................................  $ 79     $ 84
                                                              ====     ====
</Table>

8. DEBT AND OTHER CREDIT FACILITIES

     At December 31, 2001, the average interest rate on our commercial paper and
short-term borrowings was 3.2%, and at December 31, 2000, it was 7.6%. We had
the following short-term borrowings, including current maturities of long-term
debt, at December 31:

<Table>
<Caption>
                                                              2001     2000
                                                              -----    -----
                                                              (IN MILLIONS)
<S>                                                           <C>      <C>
Commercial paper............................................  $424     $215
Notes payable...............................................    75       78
Notes payable to unconsolidated affiliates..................    --        9
Current maturities of long-term debt........................    68      132
                                                              ----     ----
                                                              $567     $434
                                                              ====     ====
</Table>

  Credit Facilities

     We use a commercial paper program to manage our short-term cash
requirements. TGP is eligible to borrow up to $1 billion under this program.

     El Paso maintains a 3-year, $1 billion, revolving credit and competitive
advance facility under which it can conduct short-term borrowings and other
commercial credit transactions. This facility expires in 2003 and TGP is a
designated borrower under the facility. In June 2001, El Paso replaced an
existing 364-day revolving credit facility with a renewable $3 billion, 364-day
revolving credit and competitive advance facility. TGP is also a designated
borrower under this new facility. The interest rate on these facilities varies
and was based on LIBOR plus 50 basis points at December 31, 2001. No amounts
were outstanding under these facilities at December 31, 2001.

     As of December 31, 2001, TGP had $200 million under a shelf registration
statement on file with the Securities and Exchange Commission.

     The availability of borrowings under these credit and borrowing agreements
are subject to specified conditions, which we believe are currently being met.
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 these
agreements.

                                        53
<PAGE>

     Our long-term debt outstanding consisted of the following at December 31:

<Table>
<Caption>
                                                               2001      2000
                                                              ------    ------
                                                               (IN MILLIONS)
<S>                                                           <C>       <C>
Long-term debt
  El Paso Tennessee
     Notes, 7.25% through 10.0%, due 2008 through 2025......  $   51    $   51
     Debentures, 6.5% through 10.0%, due 2001 through
      2005..................................................      12        36
  Tennessee Gas Pipeline
     Debentures, 6.0% through 7.625% due 2011 through
      2037..................................................   1,386     1,386
  EPEC Corporation
     Senior note, 9.625% due 2001...........................      --        13
  Field Services
     Notes, 7.41% through 11.5% due 2001 through 2012.......     164       511
Other.......................................................      30         1
                                                              ------    ------
                                                               1,643     1,998
  Less: Unamortized discount, net...........................      12        21
        Current maturities..................................      68       132
                                                              ------    ------
  Long-term debt, less current maturities...................  $1,563    $1,845
                                                              ======    ======
</Table>

     Aggregate maturities of the principal amounts of long-term debt for the
next 5 years and in total thereafter are as follows:

<Table>
<Caption>
                                                              (IN MILLIONS)
                                                              -------------
<S>                                                           <C>
2002........................................................     $   68
2003........................................................          3
2004........................................................         31
2005........................................................         51
2006........................................................          3
Thereafter..................................................      1,487
                                                                 ------
          Total long-term debt, including current
           maturities.......................................     $1,643
                                                                 ======
</Table>

9. MINORITY INTEREST

     Gemstone.  As part of the Gemstone transaction, our wholly owned
subsidiary, Topaz Investors, L.L.C., issued a minority member interest to a
third party investor of Gemstone for $300 million. The third party investor is
entitled to a cumulative preferred return of 8.03% on its interest. The
agreements underlying this transaction expire in 2004, or earlier if we sell the
international power assets owned indirectly by Topaz. The minority member
interest is redeemable at liquidation value plus accrued and unpaid dividends.

10. COMMITMENTS AND CONTINGENCIES

  Legal Proceedings

     Several of our subsidiaries and affiliates were named defendants in eleven
purported class action, municipal or individual lawsuits, and in one shareholder
derivative lawsuit, filed in the California state courts. The eleven suits
contend that the defendants acted improperly to limit the construction of new
pipeline capacity to California and/or to manipulate the price of natural gas
sold into the California marketplace. The shareholder derivative suit contends
that El Paso, through its directors, failed to prevent the conduct alleged in
several of these underlying cases. We have consolidated nine of the eleven
underlying suits into a single San Diego court proceeding, and expect to
consolidate the remaining two suits in the near future. In March 2002, the
derivative lawsuit was dismissed in California, to be refiled in a state court
in Houston, Texas. A listing of these cases is included under the heading Cases
below.

                                        54
<PAGE>

     In September 2001, we received a civil document subpoena from the
California Department of Justice, seeking information said to be relevant to the
Department's ongoing investigation into the high electricity prices in
California. We have produced and expect to continue to produce materials
pursuant to this subpoena.

     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 under
report 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. 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.

     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. 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 Quinque
complaint was transferred to the same court handling the Grynberg complaint and
has now been sent back to the Kansas State Court for further proceedings. A
motion to dismiss this case is pending.

     In addition, 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 these matters, we evaluate the merits of the case,
our exposure to the matter and 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 make the necessary accruals. As new
information becomes available, our estimates may change. The impact of these
changes may have a material effect on our results of operations. As of December
31, 2001, we had reserves totaling $95 million for all outstanding legal
matters.

     While the outcome of the matters discussed above cannot be predicted with
certainty, based on information known to date and our existing accruals, we do
not expect the ultimate resolution of these matters will have a material adverse
effect on our financial position, operating results or cash flows.

  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, 2001, we had a reserve of approximately $140 million
for expected remediation costs. In addition, we expect to make capital
expenditures for environmental matters of approximately $87 million in the
aggregate for the years 2002 through 2006. These expenditures primarily relate
to compliance with clean air regulations.

     In November 1988, the Kentucky environmental agency filed a complaint in a
Kentucky state court alleging that TGP discharged pollutants into the waters of
the state and disposed of polychlorinated biphenyls (PCBs) without a permit. The
agency sought an injunction against future discharges, an order to remediate or
remove PCBs, and a civil penalty. TGP entered into agreed orders with the agency
to resolve many of the issues raised in the original allegations and received
water discharge permits from the agency for its Kentucky compressor stations.
The relevant Kentucky compressor stations are being characterized and remediated
under a 1994 consent order with the EPA. Despite these remediation efforts, the
agency may raise additional technical issues or require additional remediation
work in the future.

     Since 1988, TGP has been engaged in an internal project to identify and
deal with the presence of PCBs and other substances, including those on the EPA
List of Hazardous Substances, at compressor stations and other facilities it
operates. While conducting this project, TGP has been in frequent contact with
federal and state regulatory agencies, both through informal negotiation and
formal entry of consent orders, to ensure that its efforts meet regulatory
requirements.

                                        55
<PAGE>

     In May 1995, following negotiations with its customers, TGP filed a
stipulation and agreement with the Federal Energy Regulatory Commission (FERC)
that established a mechanism for recovering a substantial portion of the
environmental costs identified in its internal project. The stipulation and
agreement was effective July 1, 1995. Refunds may be required to the extent
actual eligible expenditures are less than amounts collected.

     TGP is a party in proceedings involving federal and state authorities
regarding the past use of PCBs in its starting air systems. TGP executed a
consent order in 1994 with the EPA governing the remediation of the relevant
compressor stations and is working with the EPA and the relevant states
regarding those remediation activities. TGP is also working with the
Pennsylvania and New York environmental agencies regarding remediation and
post-remediation activities at the Pennsylvania and New York stations.

     We have been designated, and 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 6 active
sites under CERCLA or state equivalents. We have sought to resolve our liability
as a PRP at these CERCLA sites, as appropriate, through indemnification by third
parties and settlements which provide for payment of our allocable share of
remediation costs. As of December 31, 2001, we have estimated our share of the
remediation costs at these sites to be between $1 million and $2 million and
have provided reserves that we believe are adequate for such costs. 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 the determination of our estimated
liabilities. We presently believe that based on our existing reserves, and
information known to date, the impact the costs associated with these CERCLA
sites will not have a material adverse effect on our financial position,
operating results or cash flows.

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

  Rates and Regulatory Matters

     In April 2000, the California Public Utilities Commission (CPUC) filed a
complaint with FERC alleging that El Paso Natural Gas Company's (EPNG), a
subsidiary of El Paso Corporation, sale of approximately 1.2 Bcf/d of California
capacity to El Paso Merchant Energy Company, our subsidiary, was
anti-competitive and an abuse of the affiliate relationship under FERC's
policies. Other parties in the proceeding requested that the original complaint
be set for hearing and that Merchant Energy pay back any profits it has earned
under the contract. In March 2001, FERC established a hearing, before an
administrative law judge, to address the issue of whether EPNG and/or Merchant
Energy had market power and, if so, had exercised it. In October 2001, the
administrative law judge issued a proposed decision finding that El Paso did not
exercise market power and that the market power portion of the CPUC's complaint
should be dismissed. The decision further found that El Paso had violated FERC's
marketing affiliate regulations. The judge's proposed decision has been briefed
to, and will be effective only if approved by, the FERC. On October 30, 2001,
the Market Oversight and Enforcement (MOE) section of the FERC's office of the
General Counsel filed comments in this proceeding stating that record
development at the trial was inadequate to conclude that EPNG complied with
FERC's regulation. We filed a motion to strike the MOE's pleading, but in
December 2001, the FERC denied our motion and remanded the proceeding to the
administrative law judge for a supplemental hearing on the availability of
capacity at EPNG's California delivery points. The hearing commenced on March
21, 2002.

                                        56
<PAGE>

     In June 2001, the Western Australia regulators issued a draft rate decision
at lower than expected levels for the Dampier-to-Bunbury pipeline owned by EPIC
Energy Australia Trust, in which we have a 33 percent ownership interest and a
total investment, including financial guarantees, of approximately $182 million.
EPIC Energy Australia has appealed a variety of issues related to the draft
decision to the Western Australia Supreme Court. The appeal was heard at the
Western Australia Supreme Court in November 2001 and a decision from the court
is expected in the middle of 2002. If the draft decision rates are implemented,
the new rates will adversely impact future operating results, liquidity and debt
capacity, possibly reducing the value of our investment by up to $122 million.

     In September 2001, 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 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. We cannot predict the outcome of the NOPR, but adoption of the
regulations in substantially the form proposed would, at a minimum, place
additional administrative and operational burdens on us.

     While we cannot predict with certainty the final outcome or the timing of
the resolution of all of our rates and regulatory matters, we believe the
ultimate resolution of these issues, based on information known to date, will
not have a material adverse effect on our financial position, results of
operations or cash flows.

  Other Matters

     In December 2001, Enron Corp. and a number of its subsidiaries, including
Enron North America Corp. and Enron Power Marketing, Inc., filed for Chapter 11
bankruptcy protection in the United States Bankruptcy Court for the Southern
District of New York. El Paso, through various of its subsidiaries, had
contracts with Enron North America and Enron Power Marketing for the trading of
physical gas and power and financial derivatives. We established reserves for
potential losses related to the receivables under our marketing and trading
contracts that we believe are adequate. In addition, we have terminated most of
our trading related contracts as a result of Enron's bankruptcy filings, and are
analyzing our damage claims arising from the Enron bankruptcy proceedings.

     Our foreign investments are subject to risks and unforeseen obstacles that,
in many cases are beyond our control or ability to manage. We attempt to manage
or limit these risks through our due diligence and partner selection processes,
through the denomination of foreign transactions, where possible, in U.S.
dollars, and by maintaining insurance coverage, whenever economical and
obtainable.

     We currently have one power plant in Pakistan, with a total investment,
including financial guarantees on this project, of approximately $50 million.
While we are aware of no specific threats or actions against this power plant,
events in that region, including possible retaliation for American military
actions, could impact this project and our related investments. At this time, we
believe that through a combination of commercial insurance, political insurance,
and rights under contractual obligations, our financial exposure in Pakistan
from acts of war, hostility, terrorism, or political instability is not
material. It is possible, however, that new information, future developments in
the region, or the inability of a party or parties to fulfill their contractual
obligations could cause us to reassess our potential exposure.

     We also have investments in oil and natural gas, power and pipeline
projects in Argentina with an aggregate investment, including financial
guarantees, of approximately $381 million. Economic conditions in Argentina have
significantly deteriorated during 2001, and the Argentine government has
recently defaulted on its public debt obligations. In addition, the government
has imposed several changes in law in the first quarter of 2002, including: (i)
repeal of the one-to-one exchange rate for the Argentine Peso with U.S. dollar;
(ii) a mandate that all contracts and obligations previously denominated in U.S.
dollars be re-negotiated and denominated in Argentine Pesos; and (iii) a tax
imposed on hydrocarbon and potentially on electric power exports. The Argentine
Peso devaluation, combined with the new law changes, effectively convert our
projects' contracts from U.S. dollars to Argentine Pesos and will result in a
significant reduction in the value of our investments in Argentina. We are
monitoring the situation closely and will pursue all options available to us

                                        57
<PAGE>

under our political risk insurance policies and under the international
arbitration provisions of the United States -- Argentina Bilateral Investment
Treaty. Despite the current actions by project management and the options
available to us that may mitigate our exposure, we may be required to write down
our investment by a substantial amount in the first quarter of 2002.

  Cases

     The California cases discussed above are: five filed in the Superior Court
of Los Angeles County (Continental Forge Company, et al v. Southern California
Gas Company, et al, filed September 25, 2000; Berg v. Southern California Gas
Company, et al; filed December 18, 2000; County of Los Angeles v. Southern
California Gas Company, et al filed January 8, 2002; The City of Los Angeles, et
al v. Southern California Gas Company, et al and The City of Long Beach, et al
v. Southern California Gas Company, et al, both filed March 20, 2001); two filed
in the Superior Court of San Diego County (John W.H.K. Phillip v. El Paso
Merchant Energy and John Phillip v. El Paso Merchant Energy, both filed December
13, 2000); three filed in the Superior Court of San Francisco County (Sweetie's
et al v. El Paso Corporation, et al, filed March 22, 2001; Philip Hackett, et al
v. El Paso Corporation, et al, filed May 9, 2001; and California Dairies, Inc.,
et al v. El Paso Corporation, et al, filed May 21, 2001); and one filed in the
Superior Court of the State of California, County of Alameda (Dry Creek
Corporation v. El Paso Natural Gas Company, et al, filed December 10, 2001). The
shareholder derivative suit now dismissed was styled Clark, et al v. Allumbaugh,
et al, Superior Court of Orange County, filed August 23, 2001.

  Capital Commitments and Purchase Obligations

     At December 31, 2001, we had capital and investment commitments of $1.5
billion primarily relating to our pipeline and international power activities.
Our other planned capital and investment projects are discretionary in nature,
with no substantial capital commitments made in advance of the actual
expenditures. We have entered into unconditional purchase obligations for
products and services, including financing commitments with one of our joint
ventures, totaling $157 million at December 31, 2001. The annual obligations
under these agreements are $28 million for 2002, $25 million for 2003, $27
million for 2004 and 2005, $20 million for 2006 and $30 million in total
thereafter.

  Operating Leases

     We lease property, facilities and equipment under various operating leases.
In 1995, El Paso New Chaco Company (EPNC) entered into an unconditional lease
for the Chaco Plant. The lease term expires in 2002, at which time EPNC has an
option, and an obligation upon the occurrence of various events, to purchase the
plant for a price sufficient to pay the amount of the $77 million construction
financing, plus interest and other expenses. If EPNC does not purchase the plant
at the end of the lease term, it has an obligation to pay a residual guaranty
amount equal to approximately 87 percent of the amount financed, plus interest.
We unconditionally guaranteed all obligations of EPNC under this lease.

     In October 2001, El Paso Energy Partners acquired an interest in the title
holder of the Chaco Plant. As a result, we now make our lease payments to El
Paso Energy Partners.

                                        58
<PAGE>

     Minimum annual rental commitments at December 31, 2001, were as follows:(1)

<Table>
<Caption>
                        YEAR ENDING
                        DECEMBER 31,                          OPERATING LEASES
------------------------------------------------------------  ----------------
                                                              (IN MILLIONS)
<S>                                                           <C>
   2002.....................................................        $ 7
   2003.....................................................          3
   2004.....................................................          3
   2005.....................................................          2
   2006.....................................................          2
   Thereafter...............................................          7
                                                                    ---
          Total.............................................        $24
                                                                    ===
</Table>

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

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

     Rental expense on our operating leases for the years ended December 31,
2001, 2000 and 1999 was $30 million, $15 million, and $13 million.

11. 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. Also, El Paso maintains a defined contribution plan covering its
employees, including our employees. El Paso matches 75 percent of participant
basic contributions of up to 6 percent, with matching contributions made in El
Paso common stock, which participants may diversify at any time. El Paso is
responsible for benefits accrued under its plan and allocates the related costs
to its affiliates. See Note 15 for a summary of transactions with affiliates.

  Other Postretirement Benefits

     Following our acquisition by El Paso in 1996, we retained responsibility
for some of the postretirement medical and life insurance benefits for our
former employees of operations previously disposed of, and for employees,
including TGP employees, added as a result of the merger who were eligible to
retire on December 31, 1996, and did so on or before July 1, 1997. Medical
benefits for this closed group of retirees are subject to deductibles,
co-payment provisions, and other limitations and dollar caps on the amount of
employer costs. We have reserved the right to change these benefits. Employees
who retired after July 1, 1997, will continue to receive limited postretirement
life insurance benefits. Effective February 1, 1992, TGP began recovering
through its rates the other postretirement benefits (OPEB) costs included in the
June 1993 rate case settlement agreement. To the extent actual OPEB costs differ
from the amounts funded, a regulatory asset or liability is recorded.

                                        59
<PAGE>

     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 other postretirement benefits as of and for the twelve month
period ended September 30:

<Table>
<Caption>
                                                              2001     2000
                                                              -----    -----
                                                              (IN MILLIONS)
<S>                                                           <C>      <C>
Change in benefit obligation
  Benefit obligation at beginning of period.................  $ 249    $ 273
  Interest cost.............................................     18       19
  Participant contributions.................................     13        9
  Actuarial loss............................................     --        1
  Benefits paid.............................................    (40)     (53)
                                                              -----    -----
  Benefit obligation at end of period.......................  $ 240    $ 249
                                                              =====    =====
Change in plan assets
  Fair value of plan assets at beginning of period..........  $   6    $   6
  Actual return on plan assets..............................      2        1
  Employer contributions....................................     28       43
  Participant contributions.................................     13        9
  Benefits paid.............................................    (40)     (53)
                                                              -----    -----
  Fair value of plan assets at end of period................  $   9    $   6
                                                              =====    =====
Reconciliation of funded status
  Funded status at end of period............................  $(231)   $(243)
  Fourth quarter contributions and income...................      5       11
  Unrecognized net actuarial gain...........................     (4)      (3)
  Unrecognized prior service cost...........................     (9)     (10)
                                                              -----    -----
  Net accrued benefit cost at December 31,..................  $(239)   $(245)
                                                              =====    =====
</Table>

     The current liability portion of the postretirement benefits was $43
million as of December 31, 2001 and 2000. Benefit costs for each of three years
ended December 31 were as follows:

<Table>
<Caption>
                                                              YEAR ENDED DECEMBER 31,
                                                              ------------------------
                                                              2001      2000     1999
                                                              -----    ------    -----
                                                                   (IN MILLIONS)
<S>                                                           <C>      <C>       <C>
Benefit cost for the plans includes the following components
  Interest cost.............................................   $18     $  19      $20
  Amortization of prior service cost........................    (1)       (1)      (1)
                                                               ---     -----      ---
  Net benefit cost..........................................   $17     $  18      $19
                                                               ===     =====      ===
</Table>

     Benefit obligations are based upon actuarial estimates as described below:

<Table>
<Caption>
                                                              2001    2000
                                                              ----    ----
<S>                                                           <C>     <C>
Weighted average assumptions
  Discount rate.............................................  7.25%   7.75%
  Expected return on plan assets............................  7.50%   7.50%
</Table>

     Actuarial estimates for our postretirement benefits plans assumed a
weighted average annual rate of increase in the per capita costs of covered
health care benefits of 9.5 percent in 2001, gradually decreasing to 6 percent
by the year 2008. Assumed health care cost trends have a significant effect on
the amounts reported for other postretirement benefit plans. A one-percentage
point change in our assumed health care cost trends would have less than a $1
million increase or decrease in our obligation.

                                        60
<PAGE>

12. PREFERRED STOCK

     As of December 31, 2001, we had authorized 20 million shares of preferred
stock. In November 1996, we issued 6 million shares of Series A preferred stock.
Holders of shares of Series A preferred stock are entitled to receive cash
dividends payable quarterly at the rate of 8 1/4% of the stated value of $50 per
share. It was not redeemable at our option prior to December 31, 2001. After
December 31, 2001, the Series A Preferred Stock became redeemable at our option,
in whole or in part, upon not less than 30 days' notice at a redemption price of
$50 per share, plus unpaid dividends.

13. SEGMENT INFORMATION

     Our business activities are segregated into three segments: Pipelines,
Merchant Energy, and Field Services. These segments are strategic business units
that offer a variety of different energy products and services. We manage each
segment separately as each business requires different technology and marketing
strategies.

     Our Pipelines segment provides natural gas transmission services in the
U.S. and internationally. We conduct our activities through one wholly owned and
four partially owned interstate transmission systems along with a partially
owned natural gas storage facility.

     Our Merchant Energy segment is involved in a broad range of activities in
the wholesale energy marketplace, including asset ownership, trading and risk
management, and financial services. We buy, sell, and trade natural gas, power,
and other energy commodities throughout the world, and own or have interests in
77 power generation plants in 16 countries.

     Our Field Services segment provides natural gas gathering, products
extraction, fractionation, dehydration, purification, compression, and
intrastate transmission services. These services include gathering of natural
gas from some of the most prolific and active production areas in the United
States, including the San Juan Basin, east and south Texas, Louisiana and the
Gulf of Mexico.

     The accounting policies of the individual segments are the same as those
described in Note 1. Since earnings on equity investments can be a significant
component of earnings in several of our segments, we chose to evaluate segment
performance based on EBIT. To the extent practicable, results of operations for
the years ended December 31, 1999 and 1998 have been reclassified to conform to
the current business segment presentation, although such results are not
necessarily indicative of the results which would have been achieved had the
revised business segment structure been in effect during that period.

<Table>
<Caption>
                                                                         SEGMENTS
                                                      AS OF OR FOR THE YEAR ENDED DECEMBER 31, 2001
                                                   ----------------------------------------------------
                                                               MERCHANT    FIELD
                                                   PIPELINES    ENERGY    SERVICES   OTHER(1)    TOTAL
                                                   ---------   --------   --------   --------   -------
                                                                      (IN MILLIONS)
<S>                                                <C>         <C>        <C>        <C>        <C>
Revenue from external customers
  Domestic.......................................   $  653     $29,408     $1,246      $   3    $31,310
  Foreign........................................       --       1,672         --         --      1,672
Intersegment revenue.............................       77          46        467       (590)        --
Merger-related costs and asset impairment
  charges........................................        1          74         33         --        108
Depreciation, depletion and amortization.........      128          36         86          4        254
Operating income (loss)..........................      301         588         80         (8)       961
Other income.....................................       21         313          2         --        336
</Table>

                                        61
<PAGE>

<Table>
<Caption>
                                                                         SEGMENTS
                                                      AS OF OR FOR THE YEAR ENDED DECEMBER 31, 2001
                                                   ----------------------------------------------------
                                                               MERCHANT    FIELD
                                                   PIPELINES    ENERGY    SERVICES   OTHER(1)    TOTAL
                                                   ---------   --------   --------   --------   -------
                                                                      (IN MILLIONS)
<S>                                                <C>         <C>        <C>        <C>        <C>
EBIT.............................................      322         901         81         (7)     1,297
Extraordinary items, net of income taxes.........      (27)         --         --         65         38
Cumulative effect of accounting change net of
  income taxes...................................       --          10         --         --         10
Assets
  Domestic.......................................    5,047      10,471      2,517        437     18,472
  Foreign........................................       --       1,523         --         --      1,523
Capital expenditures and investments in
  unconsolidated affiliates......................      335         811         82          7      1,235
Total investments in unconsolidated affiliates...      161       2,453        211         --      2,825
</Table>

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

(1) Includes Corporate and eliminations.

<Table>
<Caption>
                                                                         SEGMENTS
                                                      AS OF OR FOR THE YEAR ENDED DECEMBER 31, 2000
                                                   ----------------------------------------------------
                                                               MERCHANT    FIELD
                                                   PIPELINES    ENERGY    SERVICES   OTHER(1)    TOTAL
                                                   ---------   --------   --------   --------   -------
                                                                      (IN MILLIONS)
<S>                                                <C>         <C>        <C>        <C>        <C>
Revenue from external customers
  Domestic.......................................   $  707     $18,467     $  574      $   2    $19,750
  Foreign........................................       --       1,038         --         --      1,038
Intersegment revenue.............................       69          16         84       (169)        --
Merger-related costs and asset impairment
  charges........................................       --          --         11         --         11
Depreciation, depletion and amortization.........      135          27         58          3        223
Operating income (loss)..........................      335         433         84        (12)       840
Other income (loss)..............................       19         130          4         (5)       148
EBIT.............................................      354         563         88        (17)       988
Extraordinary items, net of income taxes.........      (54)         --        (19)       131         58
Assets
  Domestic.......................................    4,991       9,749      2,543        250     17,533
  Foreign........................................       --       1,932         --         --      1,932
Capital expenditures and investments in
  unconsolidated affiliates......................      186         923        451         18      1,578
Total investments in unconsolidated affiliates...      135       1,816         57         --      2,008
</Table>

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

(1) Includes Corporate and eliminations.

                                        62
<PAGE>

<Table>
<Caption>
                                                                         SEGMENTS
                                                       AS OF OR FOR THE YEAR ENDED DECEMBER 31, 1999
                                                    ---------------------------------------------------
                                                                MERCHANT    FIELD
                                                    PIPELINES    ENERGY    SERVICES   OTHER(1)   TOTAL
                                                    ---------   --------   --------   --------   ------
                                                                       (IN MILLIONS)
<S>                                                 <C>         <C>        <C>        <C>        <C>
Revenue from external customers
  Domestic........................................   $  819      $7,909     $  348      $   3    $9,079
  Foreign.........................................       --         591         --         --       591
Intersegment revenue..............................       33          20         74       (127)       --
Merger-related costs and asset impairment
  charges.........................................       --          67          8         --        75
Depreciation, depletion and amortization..........      146          46         52          3       247
Operating income (loss)...........................      360         (91)        46        (17)      298
Other income......................................       23          94         32         --       149
EBIT..............................................      383           3         78        (17)      447
Cumulative effect of accounting change net of
  income taxes....................................       --         (13)        --         --       (13)
Assets
  Domestic........................................    5,036       2,119      1,053        220     8,428
  Foreign.........................................       --       1,336         --         --     1,336
Capital expenditures and investments in
  unconsolidated affiliates.......................      231         994        141          7     1,373
Total investments in unconsolidated affiliates....      123       1,274        112         --     1,509
</Table>

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

(1) Includes Corporate and eliminations.

     The reconciliations of EBIT to income before extraordinary items and
cumulative effect of accounting change are presented below.

<Table>
<Caption>
                                                               FOR THE YEAR ENDED
                                                                  DECEMBER 31,
                                                              --------------------
                                                               2001    2000   1999
                                                              ------   ----   ----
                                                                 (IN MILLIONS)
<S>                                                           <C>      <C>    <C>
Income before interest, income taxes, and other charges.....  $1,297   $988   $447
Non-affiliated interest and debt expense....................     149    142    136
Affiliated interest and debt expense, net...................     155    122     40
Minority interest...........................................       4     --     --
Income taxes................................................     320    242     85
                                                              ------   ----   ----
          Income before extraordinary items and cumulative
            effect of accounting change.....................  $  669   $482   $186
                                                              ======   ====   ====
</Table>

     As of December 31, 2001, we had no customers whose revenues exceeded 10
percent of our total revenue. In 2000, Merchant Energy had revenues of $2.1
billion from subsidiaries of Enron Corp. We did not have revenues in excess of
10 percent with any other customer in 2000.

14. SUPPLEMENTAL CASH FLOW INFORMATION

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

<Table>
<Caption>
                                                              2001    2000    1999
                                                              ----    ----    ----
                                                                 (IN MILLIONS)
<S>                                                           <C>     <C>     <C>
Interest paid...............................................  $343    $284    $208
Income tax payments (refunds)...............................    46      54      (1)
</Table>

                                        63
<PAGE>

15. 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 includes unamortized
purchase price differences of $312 million and $343 million as of December 31,
2001 and 2000, that are being amortized over the remaining life of the
unconsolidated affiliate's underlying assets. Our net ownership interest,
investments in and advances to our unconsolidated affiliates are as follows as
of December 31:

<Table>
<Caption>
                                                          NET        INVESTMENTS      ADVANCES
                                                       OWNERSHIP   ---------------   -----------
                                          COUNTRY      INTEREST     2001     2000    2001   2000
                                          -------      ---------   ------   ------   ----   ----
                                                                           (IN MILLIONS)
<S>                                   <C>              <C>         <C>      <C>      <C>    <C>
Bear Creek Storage..................                        50%    $  116   $  101   $ --   $ --
CE Generation.......................                        50%       360      354     --     --
Chaparral Investors (Electron)......                        20%       341      268    343     --
El Paso Production Offshore I, LP...                        49%       110       --     --     --
El Paso Energy Partners.............                         7%        64       51     --     --
Other Domestic Investments(1).......                    various       257      133     38     --
                                                                   ------   ------   ----   ----
          Domestic..................                               $1,248   $  907   $381   $ --
                                                                   ------   ------   ----   ----

CAPSA/CAPEX.........................     Argentina          45%    $  259   $  282   $ --   $ --
Gasoducto del Pacifico Pipeline
  (Argentina to Chile)..............  Argentina/Chile       16%        71       70     --     --
Bolivia to Brazil Pipeline..........  Bolivia/Brazil         8%        50       53     --     --
Porto Velho (Gemstone)(2)...........      Brazil             --        --       99     --     --
Diamond Power (Gemstone)(2).........      Brazil            50%       555       --     --     --
Meizhou Wan Generating..............       China            25%        76        7     --     --
Enfield Power.......................        UK              25%        53       40     --     --
Korea Independent Energy
  Corporation.......................       Korea            50%       104      108     --     --
Samalayuca..........................      Mexico            41%       103       93     --     --
Aguaytia Energy.....................       Peru             24%        52       26     --     --
East Asia Power.....................    Philippines         46%        --       51     --     67
Other Foreign Investments(1)........      various       various       254      272      9     44
                                                                   ------   ------   ----   ----
          Foreign...................                               $1,577   $1,101   $  9   $111
                                                                   ------   ------   ----   ----
Total investments in and advances to unconsolidated
  affiliates....................................................   $2,825   $2,008   $390   $111
                                                                   ======   ======   ====   ====
</Table>

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

(1) Denotes investments less than $50 million.

(2) Contributed to Gemstone in 2001.

                                        64
<PAGE>

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

<Table>
<Caption>
                                                             2001     2000     1999
                                                             ----     ----     ----
                                                                 (IN MILLIONS)
<S>                                                          <C>      <C>      <C>
Bear Creek Storage.........................................  $ 14     $ 13     $ 10
Bolivia to Brazil Pipeline.................................     1       --        4
CAPSA/CAPEX................................................   (12)       4        3
CE Generation..............................................    29       35       24
Chaparral Investors (Electron).............................    75       (5)      (8)
Diamond Power (Gemstone)...................................     2       --       --
East Asia Power............................................    (4)     (32)      --
Gasoducto del Pacifico Pipeline (Argentina to Chile).......     2        1       (1)
Korea Investment Energy Corporation........................    20       --       --
Porto Velho (Gemstone).....................................    (6)       1       --
Samalayuca Power...........................................    12       17       17
Other......................................................    64       27       12
                                                             ----     ----     ----
     Total earnings from our unconsolidated affiliates.....  $197     $ 61     $ 61
                                                             ====     ====     ====
</Table>

     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 $1 million and $0.5
million for December 31, 2001 and 2000 and total assets of $7 million and $47
million for December 31, 2001 and 2000:

<Table>
<Caption>
                                                              YEAR ENDED DECEMBER 31,
                                                              -----------------------
                                                              2001     2000     1999
                                                              -----    -----    -----
                                                                    (UNAUDITED)
                                                                   (IN MILLIONS)
<S>                                                           <C>      <C>      <C>
Operating results data:
  Revenues and other income.................................  $954     $753     $510
  Costs and expenses........................................   749      660      444
  Income from continuing operations.........................   205       93       66
  Net income................................................   197       61       61
</Table>

<Table>
<Caption>
                                                                DECEMBER 31,
                                                              ----------------
                                                               2001      2000
                                                              ------    ------
                                                                (UNAUDITED)
                                                               (IN MILLIONS)
<S>                                                           <C>       <C>
Financial position data:
  Current assets............................................  $  669    $  628
  Non-current assets........................................   4,944     3,917
  Short-term debt...........................................     157       239
  Other current liabilities.................................     343       230
  Long-term debt............................................   2,352     1,981
  Other non-current liabilities.............................     322       456
  Minority interest.........................................      32        37
  Equity in net assets......................................   2,407     1,602
</Table>

                                        65
<PAGE>

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

<Table>
<Caption>
                                                              YEAR ENDED DECEMBER 31,
                                                              -----------------------
                                                               2001     2000    1999
                                                              -------   -----   -----
                                                                   (IN MILLIONS)
<S>                                                           <C>       <C>     <C>
Revenues....................................................  $  530    $142    $ 24
Cost of sales...............................................   2,818     369     416
Management fee income from unconsolidated affiliates........     150      82      20
Reimbursement for costs.....................................     104      42      17
Charges from El Paso........................................     212     160     209
Interest income from unconsolidated affiliates..............      22      13       9
</Table>

  Sabine River Investors

     During 1999, El Paso formed Sabine River Investors, L.L.C., a wholly owned
limited liability company, and other separate legal entities, for the purpose of
generating funds for El Paso to invest in capital projects and other assets. The
proceeds are collateralized by specific assets of El Paso, including our 50
percent investment in Bear Creek and 7 percent investment in El Paso Energy
Partners.

  Chaparral

     During 1999, we formed a series of companies with a third-party financial
investor that we refer to as Chaparral. Chaparral (also known as Electron) was
formed to obtain low cost financing to fund the growth of our unregulated
domestic power generation and related businesses. Chaparral has acquired and
currently owns equity interests in 39 natural gas-fired generation facilities in
Arizona, California, Colorado, Connecticut, Florida, Massachusetts, Nevada, New
Jersey, New York, Pennsylvania and Rhode Island. Chaparral also owns several
operating companies that provide the services required to operate and maintain
these facilities and a natural gas service company that provides fuel
procurement services to eight of Chaparral's natural gas-fired generation
facilities in California.

     Total third party capital in Chaparral was $1.15 billion, including $123
million contributed in 1999 and $1,027 million contributed in 2000, of which $1
billion of debt was raised in 2000 by the third party investor through a note
issuance that matures in March 2003. In order to lower the cost of this debt, El
Paso provided a contingent equity support arrangement to the third party
debtholders. El Paso plans to amend this arrangement and replace it with an El
Paso financial guaranty in 2002.

     We account for our equity investment in Chaparral of $341 million and $268
million at December 31, 2001 and 2000 using the equity method of accounting
since we do not have the ability to exercise control over the structure. We also
had a note receivable from Chaparral and its subsidiaries of $343 million and it
was included in current and long-term receivables from unconsolidated
affiliates.

     Chaparral has used its funds to acquire the domestic power generation and
related businesses described above. In some cases, Chaparral acquired these
power generation assets from us. Chaparral acquired power generation assets from
us with a value of $94 million and $659 million in 2001 and 2000. We did not
recognize any gains or losses on these transactions.

     In addition to the financing transactions described above, we have also
entered into various contractual agreements with Chaparral related to management
and trading activities.

     We serve as manager of Chaparral under a management agreement that expires
in 2006. We are compensated for the services we provide through an annual
performance-based management fee, which amounted to $147 million in 2001 and $80
million in 2000. This performance-based management fee is calculated based on
the value of Chaparral's assets as determined using cash flow techniques. We
also receive a fixed fee reimbursement for out-of-pocket and third-party
expenses we incurred on behalf of Chaparral, which was $20 million for 2001 and
2000.

                                        66
<PAGE>

     Our Merchant Energy segment also enters into various contractual agreements
with Chaparral and its operating subsidiaries in conjunction with Chaparral's
operations. These include agreements to (i) supply natural gas or other fuels to
power Chaparral's facilities; (ii) purchase all or a portion of the power
produced by Chaparral's facilities; (iii) provide some or all of the power
supply that Chaparral is obligated to provide to fulfill agreements it has with
third parties; (iv) purchase tolling rights; and (v) provide other services to
Chaparral related to its operations. We account for these agreements as trading
price risk management activities and recognized revenues of $266 million and
$119 million in 2001 and 2000 and costs of sales of $121 million and $42 million
in 2001 and 2000 related to these transactions.

  Gemstone

     In November 2001, we formed with a third-party financial investor a series
of companies that we refer to as Gemstone. Gemstone was formed to provide a
financing vehicle through which we fund the development and growth of our power
generation, merchant energy, and related businesses in Brazil.

     The third party financial investor contributed into Gemstone $50 million in
cash and raised an additional $950 million through a note issuance that matures
in October 2004. To lower the cost of this debt, El Paso provided a contingent
equity support arrangement to the third party debtholders. El Paso plans to
amend this arrangement and replace it with an El Paso financial guaranty in
2002. The proceeds were used by Gemstone to acquire a Brazilian power
investment, invest $300 million in preferred securities of one of our
consolidated subsidiaries and temporarily invest excess proceeds of $462 million
in short-term notes from El Paso. The preferred securities of our subsidiary
entitle Gemstone to a preferred return of 8.03%.

     We contributed $280 million in cash as well as several Brazilian
investments with a total value of $274 million in exchange for our interest in
Gemstone. Gemstone used the funds we contributed to acquire an interest in
electric generation assets in Brazil.

     Our investment in Gemstone as of December 31, 2001, is $555 million, and we
account for our investment using the equity method of accounting since we do not
have the ability to exercise control over the entity. We account for the
investor's preferred interest in our consolidated subsidiary as a minority
interest in our balance sheet and the preferred return as minority interest
expense in our income statement.

     Under our management agreement with Gemstone, we earn a cost-based
management fee. This fee was not significant in 2001. We have also entered into
a participation agreement with one of Gemstone's power generation interests
whereby we earn a fee for managing, constructing, and operating the related
facilities and marketing and distributing the energy produced by these
facilities. This fee was not significant in 2001.

  El Paso Energy Partners

     In 2001, as a result of a FTC order related to El Paso's merger with
Coastal, El Paso Energy Partners sold its interest in several offshore assets
including seven natural gas pipeline systems, a dehydration facility and two
offshore platforms. Proceeds from these sales were approximately $135 million
and resulted in a loss to the partnership of approximately $25 million. As
consideration for these sales, we committed to pay El Paso Energy Partners a
series of payments totaling $29 million. This amount, as well as our
proportionate share of the losses on the sale of the partnership's assets, were
recorded as merger-related costs.

     During 2001, El Paso Energy Partners issued a total of 7.9 million common
units reducing our ownership interest in the common units to 7 percent.

     We perform the daily operations for El Paso Energy Partners on behalf of
the partnership's general partner, DeepTech International Inc., an affiliate of
ours. We are reimbursed for these and other services we provide for El Paso
Energy Partners. The management agreement between DeepTech and El Paso Energy
Partners expires on June 30, 2002, and may be terminated thereafter upon 90 days
notice by either party. We recorded reimbursements of $34 million and $22
million in 2001 and 2000.

     In addition to the management activities described above, we enter into
transactions with El Paso Energy Partners in the normal course of business for
the sale of natural gas and for services such as transportation and

                                        67
<PAGE>

fractionation, storage, processing and other types of operational services.
These activities are based on the same terms as non-affiliates. We recognized
revenues of $28 million and $14 million in 2001 and 2000 and cost of sales of
$43 million and $22 million in 2001 and 2000.

     In February 2002, we announced the sale of additional midstream assets to
El Paso Energy Partners for total consideration of $750 million. The primary
assets to be sold include:

     - 9,400 miles of intrastate transmission pipelines;

     - 1,300 miles of gathering systems in the Permian Basin; and

     - a 42.3 percent non-operating interest in the Indian Basin gas processing
       and treating plant and associated gathering lines.

  El Paso and Subsidiaries

     We participate in El Paso's cash management program which matches
short-term cash surpluses and needs of its participating affiliates, thus
minimizing total borrowing from outside sources. We had net borrowings of $2,364
million at December 31, 2001, at a market rate of interest which was 2.1%. At
December 31, 2000, we had borrowed $3,690 million at a market rate of 6.7%. In
addition, we have demand note receivables with El Paso of $40 million at
December 31, 2001, with interest rates that range from 2.7% to 3.1%. At December
31, 2000, demand note receivables were $15 million, with an interest rate of
7.3%. We also had a note payable to El Paso of $35 million at December 31, 2001,
with a market rate.

     At December 31, 2001, we had accounts and notes receivable from El Paso's
subsidiaries of $56 million and $10 million at December 31, 2000. In addition,
we had accounts payable to El Paso's subsidiaries of $530 million and $69
million at December 31, 2000. The balances arose in the normal course of
business.

     El Paso allocates a portion of its general and administrative expenses to
us. The allocation is based on the estimated level of effort devoted to our
operations and the relative size of our revenues, gross property and payroll.
During 2001, we performed some operational, financial, accounting and
administrative services for subsidiaries of El Paso CGP, our affiliate. We
recorded the amounts billed as a reduction to our operating expenses. We believe
the allocation methods are reasonable.

     In addition, we enter into transactions with other El Paso subsidiaries in
the ordinary course of our business to transport, sell and purchase natural gas
and various contractual agreements for trading activities. As a result of El
Paso's merger with Coastal, our affiliated activities have increased. Services
provided by these affiliates for our benefit are based on the same terms as
non-affiliates.

                                        68
<PAGE>

16. 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
                                                            -----------   ------------   -------   --------
                                                                             (IN MILLIONS)
<S>                                                         <C>           <C>            <C>       <C>
2001
  Operating revenues......................................    $6,739         $7,747      $8,314    $10,182
  Merger-related costs and asset impairment charges.......        35             --          44         29
  Operating income........................................       211            259         190        301
  Income before extraordinary items and cumulative effect
    of accounting change..................................       211            170         120        168
  Cumulative effect of accounting change, net of income
    taxes.................................................        10             --          --         --
  Extraordinary items, net of income taxes................        --             --          38         --
  Net income..............................................       221            170         158        168
2000
  Operating revenues......................................    $7,234         $6,707      $3,980    $ 2,867
  Merger-related costs and asset impairment charges.......        11             --          --         --
  Operating income........................................       286            153         239        162
  Income before extraordinary items.......................       144             90         140        108
  Extraordinary items, net of income taxes................       (19)            --          --         77
  Net income..............................................       125             90         140        185
</Table>

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

(1) Reflects the adoption of the Emerging Issues Task Force Topic D-105. This
    policy was adopted during the fourth quarter with an effective adoption date
    of January 1, 2001. See Note 1 for a further discussion of this change in
    accounting.

                                        69
<PAGE>

                       REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and Stockholders of
El Paso Tennessee Pipeline Co.:

     In our opinion, the consolidated financial statements listed in the Index
appearing under Item 14(a)(1) present fairly, in all material respects, the
financial position of El Paso Tennessee Pipeline Co. and its subsidiaries at
December 31, 2001 and 2000, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 2001 in conformity
with accounting principles generally accepted in the United States of America.
In addition, in our opinion, the financial statement schedule listed in the
Index appearing under Item 14(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 financial
statement schedule are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements and
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 described in Notes 1 and 6, the Company adopted Statement of Financial
Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging
Activities, on January 1, 2001, and Emerging Issues Task Force Topic D-105,
Accounting in Consolidation for Energy Trading Contracts between Affiliated
Entities When the Activities of One but not Both Affiliates Are Within the Scope
of Issue 98-10 on December 31, 2001.

/s/ PricewaterhouseCoopers LLP

Houston, Texas
March 6, 2002

                                        70
<PAGE>

                                  SCHEDULE II

                         EL PASO TENNESSEE PIPELINE CO.
                       VALUATION AND QUALIFYING ACCOUNTS

                  YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
                                 (IN MILLIONS)

<Table>
<Caption>
                                          BALANCE AT   CHARGED TO   CHARGED TO                 BALANCE
                                          BEGINNING    COSTS AND      OTHER                    AT END
              DESCRIPTION                 OF PERIOD     EXPENSES     ACCOUNTS    DEDUCTIONS   OF PERIOD
              -----------                 ----------   ----------   ----------   ----------   ---------
<S>                                       <C>          <C>          <C>          <C>          <C>
2001
  Allowance for doubtful accounts.......     $100         $124(1)     $  (1)        $ --        $223
  Valuation allowance on deferred tax
     assets.............................        2           --           --           --           2
  Legal reserves........................      235           14         (124)(2)      (30)(3)      95
  Environmental reserves................      122           --           30          (12)        140
  Regulatory reserves...................       33          (12)(4)      (11)(4)       --          10
2000
  Allowance for doubtful accounts.......     $ 23         $ 85(1)     $  (4)        $ (4)(3)    $100
  Valuation allowance on deferred tax
     assets.............................        4           --           --           (2)          2
  Legal reserves........................       18            9          211(5)        (3)        235
  Environmental reserves................      130            7            1          (16)        122
  Regulatory reserves...................       38           (5)          --           --          33
1999
  Allowance for doubtful accounts.......     $ 23         $  6        $  (2)        $ (4)(3)    $ 23
  Valuation allowance on deferred tax
     assets.............................        5           --           --           (1)          4
  Legal reserves........................       33           (9)          (4)          (2)         18
  Environmental reserves................      148            2            4          (24)(3)     130
  Regulatory reserves...................      113          (75)(6)       --           --          38
</Table>

---------------
(1) Primarily relates to our Merchant Energy segment's reserves booked for
    collectibility of receivables related to Enron in 2001 and California in
    2000 and 2001.

(2) In 2001, we finalized our purchase price adjustment to property, plant and
    equipment for the legal reserves related to our PG&E acquisition.

(3) Primarily accounts written off.

(4) Upon favorable resolution of issues related to natural gas purchase
    contracts, we reversed the regulatory reserve to revenue and the regulatory
    asset account.

(5) Of this amount, $53 million was the legal reserve we acquired in connection
    with our purchase of PG&E Texas midstream operations. We recorded an
    additional $159 million in property, plant and equipment related to purchase
    price adjustments on our PG&E acquisition.

(6) Primarily represents favorable resolution of various regulatory issues.

                                        71
<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

     The information appearing under the captions "Directors Elected by Common
Stockholders," "Proposal No. 1 -- Nominee for Election of Director by Series A
Preferred Stockholders" and "Section 16(a) Beneficial Ownership Reporting
Compliance" in our proxy statement for the 2002 Annual Meeting of Stockholders
is incorporated herein by reference. Information regarding our executive
officers is presented in Item 1, Business, of this Form 10-K under the caption
"Executive Officers of the Registrant" and is incorporated herein by reference.

ITEM 11. EXECUTIVE COMPENSATION

     Information appearing under the caption "Executive Compensation" in our
proxy statement for the 2002 Annual Meeting of Stockholders is incorporated
herein by reference.

ITEM 12. SECURITY OWNERSHIP OF BENEFICIAL OWNERS AND MANAGEMENT

     Information appearing under the captions "Security Ownership of a
Beneficial Owner and Management of the Company" and "Security Ownership of
Management of El Paso Corporation" in our proxy statement for the 2002 Annual
Meeting of Stockholders is incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     Information appearing under the caption "Relationship with El Paso
Corporation" in our proxy statement for the 2002 Annual Meeting of Stockholders
is incorporated herein by reference.

                                        72
<PAGE>

                                    PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

     (a) THE FOLLOWING DOCUMENTS ARE FILED AS A PART OF THIS REPORT:

      1. Financial statements.

     Our consolidated financial statements included in Part II, Item 8 of this
report:

<Table>
<Caption>
                                                                PAGE
                                                                ----
<S>                                                           <C>
     Consolidated Statements of Income......................     33
     Consolidated Balance Sheets............................     34
     Consolidated Statements of Cash Flows..................     36
     Consolidated Statements of Stockholders' Equity........     37
     Consolidated Statements of Comprehensive Income and
      Changes in Accumulated Other Comprehensive Income.....     38
     Notes to Consolidated Financial Statements.............     39
     Report of Independent Accountants......................     70
</Table>

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

<Table>
<S>                                                           <C>
     Schedule II -- Valuation and qualifying accounts.......     71
     Schedules other than that listed above are omitted
      because they are not applicable

 3. Exhibit list............................................     74
</Table>

     (b) REPORTS ON FORM 8-K:

     None.

                                        73
<PAGE>

                         EL PASO TENNESSEE PIPELINE CO.

                                  EXHIBIT LIST
                               DECEMBER 31, 2001

     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.

<Table>
<Caption>
        EXHIBIT
         NUMBER                                  DESCRIPTION
        -------                                  -----------
<C>                      <S>
         3.A             -- Restated Certificate of Incorporation, dated May 11, 1999
                            (Exhibit 3.A to our 1999 First Quarter Form 10-Q).
         3.B             -- By-laws as amended March 1, 1998 (Exhibit 3.B to our 1997
                            Form 10-K).
         4.A             -- Indenture dated as of March 4, 1997, between TGP and The
                            Chase Manhattan Bank (Exhibit 4.1 to our 1997 Form 10-K);
                            First Supplemental Indenture dated as of March 13, 1997,
                            between TGP and The Chase Manhattan Bank (Exhibit 4.2 to
                            our 1997 Form 10-K); Second Supplemental Indenture dated
                            as of March 13, 1997, between TGP and The Chase Manhattan
                            Bank (Exhibit 4.3 to our 1997 Form 10-K); Third
                            Supplemental Indenture dated as of March 13, 1997,
                            between TGP and The Chase Manhattan Bank (Exhibit 4.4 to
                            our 1997 Form 10-K); Fourth Supplemental Indenture dated
                            as of October 9, 1998, between TGP and The Chase
                            Manhattan Bank (Exhibit 4.2 to our Form 8-K filed October
                            9, 1998).
        10.A             -- $3,000,000,000 364-Day Revolving Credit and Competitive
                            Advance Facility Agreement, dated as of August 11, 2001,
                            by and among El Paso, EPNG, TGP, the several banks and
                            other financial institutions from time to time parties to
                            the Agreement, The Chase Manhattan Bank, Citibank N.A.
                            and ABN Amro Bank, N.V. as co-documentation agents for
                            the Lenders and Bank of America, N.A. as syndication
                            agent for the Lenders (Exhibit 10.A to our 2001 Second
                            Quarter Form 10-Q).
        10.B             -- $1,000,000,000 3-Year Revolving Credit and Competitive
                            Advance Facility Agreement dated as of August 4, 2000, by
                            and among El Paso, EPNG, TGP, the several banks and other
                            financial institutions from time to time parties to the
                            Agreement, The Chase Manhattan Bank, Citibank N.A. and
                            ABN Amro Bank, N.V. as co-documentation agents for the
                            Lenders and Bank of America, N.A. as syndication agent
                            for the Lenders (Exhibit 10.B to our 2000 Third Quarter
                            Form 10-Q).
       *21               -- List of Subsidiaries.
</Table>

UNDERTAKING

     The undersigned Registrant hereby undertakes, pursuant to Regulation S-K,
Item 601(b), paragraph (4)(iii), to furnish to the Securities and Exchange
Commission upon request all constituent instruments defining the rights of
holders of long-term debt of Registrant and its consolidated subsidiaries not
filed herewith for the reason that the total amount of securities authorized
under any of such instruments does not exceed 10 percent of the total
consolidated assets of Registrant and its consolidated subsidiaries.

                                        74
<PAGE>

                                   SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, as amended, El Paso Tennessee Pipeline Co. has duly caused
this report to be signed on its behalf by the undersigned, thereunto duly
authorized on the 25th day of March 2002.

                                          EL PASO TENNESSEE PIPELINE CO.
                                                            Registrant

                                          By:      /s/ WILLIAM A. WISE
                                            ------------------------------------
                                                      William A. Wise
                                              Chairman of the Board, President
                                                and Chief Executive Officer

     Pursuant to the requirements of the Securities Exchange Act of 1934, as
amended, this report has been signed below by the following persons on behalf of
El Paso Tennessee Pipeline Co. and in the capacities and on the dates indicated.

<Table>
<Caption>
                 SIGNATURE                                  TITLE                          DATE
                 ---------                                  -----                          ----
<C>                                           <S>                                <C>

            /s/ WILLIAM A. WISE               Chairman of the Board, President,            March 25, 2002
--------------------------------------------  Chief Executive Officer and
             (William A. Wise)                Director (Principal Executive
                                              Officer)

            /s/ H. BRENT AUSTIN               Executive Vice President, Chief              March 25, 2002
--------------------------------------------  Financial Officer and Director
             (H. Brent Austin)                (Principal Financial Officer)

           /s/ JOEL RICHARDS III              Executive Vice President and                 March 25, 2002
--------------------------------------------  Director
            (Joel Richards III)

             /s/ PEGGY A. HEEG                Executive Vice President: Law                March 25, 2002
--------------------------------------------
              (Peggy A. Heeg)

           /s/ JEFFREY I. BEASON              Senior Vice President, Controller            March 25, 2002
--------------------------------------------  and Director (Principal Accounting
            (Jeffrey I. Beason)               Officer)

           /s/ KENNETH L. SMALLEY             Director                                     March 25, 2002
--------------------------------------------
            (Kenneth L. Smalley)
</Table>

                                        75
<PAGE>

                               INDEX TO EXHIBITS

     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.

<Table>
<Caption>
        EXHIBIT
         NUMBER                                  DESCRIPTION
        -------                                  -----------
<C>                      <S>
         3.A             -- Restated Certificate of Incorporation, dated May 11, 1999
                            (Exhibit 3.A to our 1999 First Quarter Form 10-Q).
         3.B             -- By-laws as amended March 1, 1998 (Exhibit 3.B to our 1997
                            Form 10-K).
         4.A             -- Indenture dated as of March 4, 1997, between TGP and The
                            Chase Manhattan Bank (Exhibit 4.1 to our 1997 Form 10-K);
                            First Supplemental Indenture dated as of March 13, 1997,
                            between TGP and The Chase Manhattan Bank (Exhibit 4.2 to
                            our 1997 Form 10-K); Second Supplemental Indenture dated
                            as of March 13, 1997, between TGP and The Chase Manhattan
                            Bank (Exhibit 4.3 to our 1997 Form 10-K); Third
                            Supplemental Indenture dated as of March 13, 1997,
                            between TGP and The Chase Manhattan Bank (Exhibit 4.4 to
                            our 1997 Form 10-K); Fourth Supplemental Indenture dated
                            as of October 9, 1998, between TGP and The Chase
                            Manhattan Bank (Exhibit 4.2 to our Form 8-K filed October
                            9, 1998).
        10.A             -- $3,000,000,000 364-Day Revolving Credit and Competitive
                            Advance Facility Agreements dated as of August 11, 2001,
                            by and among El Paso, EPNG, TGP, the several banks and
                            other financial institutions from time to time parties to
                            the Agreement, The Chase Manhattan Bank, Citibank N.A.
                            and ABN Amro Bank, N.V. as co-documentation agents for
                            the Lenders and Bank of America, N.A. as syndication
                            agent for the Lenders (Exhibit 10.A to our 2001 Second
                            Quarter Form 10-Q).
        10.B             -- $1,000,000,000 3-Year Revolving Credit and Competitive
                            Advance Facility Agreement dated as of August 4, 2000, by
                            and among El Paso, EPNG, TGP, the several banks and other
                            financial institutions from time to time parties to the
                            Agreement, The Chase Manhattan Bank, Citibank N.A. and
                            ABN Amro Bank, N.V. as co-documentation agents for the
                            Lenders and Bank of America, N.A. as syndication agent
                            for the Lenders (Exhibit 10.B to our 2000 Third Quarter
                            Form 10-Q).
       *21               -- List of Subsidiaries.
</Table>