<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 1-7176

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

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

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

                        TELEPHONE NUMBER: (713) 420-2600

          SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:

<Table>
<Caption>
                                                               NAME OF EACH EXCHANGE
TITLE OF EACH CLASS                                             ON WHICH REGISTERED
-------------------                                            ---------------------
<S>                                                           <C>
8.375% Coastal Trust Preferred Securities issued by Coastal
  Finance I
Growth PRIDES                                                 New York Stock Exchange
Income PRIDES
</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, 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: NONE
    INDICATE THE NUMBER OF SHARES OUTSTANDING AT EACH OF THE REGISTRANTS'
CLASSES OF COMMON STOCK, AS OF THE LATEST PRACTICABLE DATE.
    Common Stock, par value $1.00 per share. Shares outstanding on March 28,
2002: 1,000

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

                   DOCUMENTS INCORPORATED BY REFERENCE: NONE

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


<PAGE>

                              EL PASO CGP COMPANY

                               TABLE OF CONTENTS

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

Item 1.     Business....................................................    1
Item 2.     Properties..................................................   17
Item 3.     Legal Proceedings...........................................   17
Item 4.     Submission of Matters to a Vote of Security Holders.........    *

                                   PART II

Item 5.     Market for Registrant's Common Equity and Related
              Stockholder Matters.......................................   18
Item 6.     Selected Financial Data.....................................    *
Item 7.     Management's Discussion and Analysis of Financial Condition
              and Results of Operations.................................   18
            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.................   31
Item 9.     Changes in and Disagreements with Accountants on Accounting
              and Financial Disclosure..................................   77

                                   PART III

Item 10.    Directors and Executive Officers of the Registrant..........    *
Item 11.    Executive Compensation......................................    *
Item 12.    Security Ownership of Management............................    *
Item 13.    Certain Relationships and Related Transactions..............    *

                                   PART IV

Item 14.    Exhibits, Financial Statement Schedules, and Reports on Form
              8-K.......................................................   77
            Signatures..................................................   98
</Table>

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

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

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

<Table>
<S>      <C>
/d       = per day
Bbl      = barrels
BBtu     = billion British thermal units
         = billion British thermal unit
BBtue    equivalents
Bcf      = billion cubic feet
Bcfe     = billion cubic feet of gas equivalents
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
Tcfe     = trillion cubic feet of gas equivalents
</Table>

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

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

                                        i
<PAGE>

                                     PART I

ITEM 1. BUSINESS.

                                    GENERAL

     We are a Delaware corporation originally founded in 1955. In January 2001,
we became a wholly owned subsidiary of El Paso Corporation through our merger
with a wholly owned El Paso subsidiary. In the merger, holders of our common
stock and Class A common stock received 1.23 shares of El Paso common stock for
each outstanding common share; holders of our Series A and Series B convertible
preferred stock received 9.133 shares of El Paso common stock for each
outstanding convertible preferred share; and holders of our Series C convertible
preferred stock received 17.98 shares of El Paso common stock for each
outstanding convertible preferred share. In addition, holders of our outstanding
stock options received shares of El Paso common stock based on the fair value of
these options on the date of the merger. As a result, El Paso owns 100 percent
of our common equity. On January 30, 2001, we changed our name from The Coastal
Corporation to El Paso CGP Company.

     Our principal operations include:

        - natural gas transportation, gathering, processing and storage;

        - natural gas and oil exploration, development and production;

        - energy and energy-related commodities and product marketing;

        - power generation;

        - energy infrastructure facility development and operation;

        - petroleum refining;

        - chemicals production; and

        - coal mining.

                                    SEGMENTS

     Our operations are segregated into four primary business segments:
Pipelines, Merchant Energy, Production 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. These segments changed from those reported
in 2000 as a result of our merger with El Paso. Information for all prior
periods has been restated to reflect the current segment presentation. 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
15, which is incorporated herein by reference.

     Our Pipelines segment owns or has interests in approximately 20,300 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
four of the largest consuming regions in the U.S.: the Gulf Coast, California,
the Northeast and the Midwest. Our U.S. pipeline systems also own or have
interests in over 280 Bcf of storage capacity used to provide a variety of
services to our customers. Our international pipeline operations include access
between our U.S. based systems and Canada.

     Our Merchant Energy segment is involved in a broad range of energy-related
activities including asset ownership and marketing and trading. We buy, sell and
trade crude oil, refined products, coal 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 18 facilities in 8 countries. The three
refineries we operate have the capacity to process approximately 438 MBbls of
crude oil per day and produce a variety of petroleum products. We also

                                        1
<PAGE>

produce agricultural and industrial chemicals at five facilities in the U.S. Our
coal mining operations produce high-quality, bituminous coal with reserves in
Kentucky, Virginia and West Virginia.

     Our Production segment leases approximately 2 million net acres in 14
states, including Colorado, Texas, Utah, West Virginia and Wyoming, and in the
Gulf of Mexico. We also have exploration and production rights in Australia,
Bolivia, Brazil, Canada, Hungary and Indonesia. During 2001, daily equivalent
natural gas production was 1.2 Bcfe/d, and our reserves at December 31, 2001,
were approximately 4.3 Tcfe.

     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 4,000 natural gas wells with approximately 4,500 miles of natural gas
gathering and natural gas liquids pipelines, and 14 natural gas processing,
treating and fractionation facilities located in some of the most active
production areas in the U.S., including east and south Texas, Louisiana and the
Rocky Mountains.

                               PIPELINES SEGMENT

     Our Pipelines segment provides natural gas transmission services in the
U.S. and internationally. We conduct our activities through three wholly owned
and three partially owned interstate transmission systems along with five
underground natural gas storage facilities. The tables below detail our wholly
owned and partially owned interstate transmission systems:

                  WHOLLY OWNED INTERSTATE TRANSMISSION SYSTEMS

<Table>
<Caption>
                                                                                                     AVERAGE
                                                                                                  THROUGHPUT(1)
      TRANSMISSION                        SUPPLY AND                   MILES OF     DESIGN    ---------------------   STORAGE
         SYSTEM                         MARKET REGION                  PIPELINE    CAPACITY   2001    2000    1999    CAPACITY
      ------------                      -------------                 ----------   --------   -----   -----   -----   --------
                                                                                   (MMCF/D)         (BBTU/D)           (BCF)
<S>                       <C>                                         <C>          <C>        <C>     <C>     <C>     <C>
ANR Pipeline              Extends from Texas, Oklahoma, Louisiana      10,600       6,394     3,776   3,807   3,515    202
  (ANR)                   and the Gulf of Mexico to the Midwest and
                          northeast regions of the U.S., including
                          Detroit, Chicago and Milwaukee.

Colorado Interstate Gas   Extends from most production areas in the    4,600        2,928     1,448   1,383   1,301    29
  (CIG)                   Rocky Mountain region and the Anadarko
                          Basin to the front range of the Rocky
                          Mountains and various interconnects with
                          pipeline systems transporting gas to the
                          Midwest, the Southwest, California and the
                          Pacific Northwest.

Wyoming Interstate        Extends from western Wyoming and the          600         1,860     1,017     832     657    --
  (WIC)                   Powder River Basin to the CIG-Trailblazer
                          interconnect near Cheyenne, Wyoming on the
                          800-mile Trailblazer system and into other
                          interstate and intrastate pipelines.
</Table>

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

(1) Includes throughput transported on behalf of affiliates.

                                        2
<PAGE>

                PARTIALLY OWNED INTERSTATE TRANSMISSION SYSTEMS

<Table>
<Caption>
                                                                                                                   AVERAGE
                                                                                                                THROUGHPUT(1)
         TRANSMISSION                         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>
Alliance Pipeline(2)             Extends from western Canada to           14        2,345        1,537      1,479    105       --
                                 Chicago.

Great Lakes Gas Transmission     Extends from the Manitoba-Minnesota      50        2,100        2,895      2,224   2,477   2,602
                                 border to the Michigan-Ontario
                                 border at St. Clair, Michigan.

Overthrust Pipeline Company      Extends from the Whitney Canyon area     10           88          227        87      85      140
                                 near the Utah-Wyoming border to Rock
                                 Springs, Wyoming.
</Table>

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

(1) Volumes represent the systems' total design capacity and average throughput
    and are not adjusted for our ownership interest.
(2) The Alliance pipeline project commenced operations in the fourth quarter of
    2000.

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

                   UNDERGROUND NATURAL GAS STORAGE FACILITIES

<Table>
<Caption>
                                                              OWNERSHIP     STORAGE
STORAGE FACILITY                                              INTEREST    CAPACITY(1)   LOCATION
----------------                                              ---------   -----------   --------
                                                              (PERCENT)      (BCF)
<S>                                                           <C>         <C>           <C>
ANR Storage................................................    100          56          Michigan
Blue Lake Gas Storage......................................     75          47          Michigan
Eaton Rapids Gas Storage...................................     50          13          Michigan
Steuben Gas Storage........................................     50           6          New York
Young Gas Storage..........................................     48           5          Colorado
</Table>

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

(1) Includes a total of 75 Bcf contracted to affiliates. Storage capacity is
    under long-term contracts and is not adjusted for our ownership interest.

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

<Table>
<Caption>
TRANSMISSION                                                                                      ANTICIPATED
   SYSTEM        PROJECT     CAPACITY                      DESCRIPTION(1)                       COMPLETION DATE
------------     -------     --------                      --------------                      -----------------
                             (MMCF/D)
<S>            <C>           <C>        <C>                                                    <C>
ANR            PG&E Badger     210      A lateral pipeline to supply natural gas to a PG&E         May 2004
                                        facility located in southeast Wisconsin.

CIG            Front Range     283      Installation of compression and pipeline looping to      December 2002
                Expansion               increase deliverability along the Colorado Front
                                        Range market area.
</Table>

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

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

                                        3
<PAGE>

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 each system provides services
to its 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;

     - depreciation and amortization policies;

     - acquisition and disposition of facilities; and

     - initiation and discontinuation of services.

     Our wholly and partially owned domestic pipelines and storage facilities
have tariffs established through filings with the FERC that have a variety of
terms and conditions, each of which affects their operations and their ability
to recover fees for the services they provide. Generally, changes to these fees
or terms of service can only be implemented upon approval by the FERC.

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

     Our interstate pipeline systems are also subject to the Natural Gas
Pipeline Safety Act of 1968, which establishes pipeline safety requirements, the
National Environmental Policy Act and other environmental legislation. Each of
our systems 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 and storage facilities by the U.S. Department of
Transportation. Additionally, we are subject to similar safety requirements from
the U.S. Department of Labor's Occupational Safety and Health Administration
related to our processing plants. 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 13.

                                        4
<PAGE>

  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. The following table details our markets and competition
on each of our wholly owned pipeline systems:

<Table>
<Caption>
  TRANSMISSION
     SYSTEM         CUSTOMER INFORMATION(1)            CONTRACT INFORMATION                    COMPETITION
----------------  ----------------------------  ----------------------------------  ----------------------------------
<S>               <C>                           <C>                                 <C>
ANR               Approximately 250 firm and    Approximately 600 firm contracts    In Wisconsin and Michigan, ANR
                    interruptible customers     Contracted capacity: 97%            competes with other interstate and
                                                Remaining contract term: 5 months   intrastate pipeline companies and
                                                to   23 years                       local distribution companies in
                                                Average remaining contract term:    the transportation and storage of
                                                  5 years                           natural gas. In the Northeast
                                                                                    markets, ANR competes with other
                  Major Customer:                                                   interstate pipelines serving
                  Wisconsin Gas Company                                             electric generation and local
                  (772 BBtu/d)                  Contract terms expire in            distribution companies. Also,
                                                2002-2008.                          Wisconsin Gas is a sponsor of the
                                                                                    proposed Guardian Pipeline, which
                                                                                    is expected to be in service by
                                                                                    the spring of 2002, and will
                                                                                    directly compete for a portion of
                                                                                    the markets served by ANR's
                                                                                    expiring capacity.

CIG               Approximately 165 firm and    Approximately 160 firm contracts    In CIG's "on-system" market,
                    interruptible customers     Contracted capacity: 100%           competition comes from local
                                                Remaining contract term: 2 months   supply in the Denver-Julesburg
                                                to   23 years                       basin, from an intrastate pipeline
                                                Average remaining contract term:    directly serving Denver and from
                                                  7 years                           off-system shippers who can
                  Major Customer:                                                   deliver their gas in that market,
                  Public Service Company of                                         supplanting CIG transportation for
                      Colorado (1,231 BBtu/d)   Contract term expires in 2007.      on-system customers. In its "off-
                                                                                    system" market, CIG faces
                                                                                    competition in its supply areas
                                                                                    from competitors who can ship
                                                                                    natural gas to the Midwest,
                                                                                    California, the Southwest and the
                                                                                    Pacific Northwest.

WIC               Approximately 45 firm and     Approximately 50 firm contracts     WIC competes with eight interstate
                    interruptible customers     Contracted capacity: 100%           pipelines and one intrastate
                                                Remaining contract term:            pipeline for supply access.
                                                9 months to 18 years                Additionally, WIC's two lines feed
                                                Average remaining contract term:    into the Trailblazer system going
                                                6 years                             east, the CIG system going south
                  Major Customers:                                                  and other interstate and
                  Colorado Interstate Gas                                           intrastate pipelines connected at
                      Company                   Contract terms expire in            the CIG-Trailblazer interconnect.
                  (247 BBtu/d)                  2003-2007.
                  Western Gas Resources
                  (206 BBtu/d)                  Contract terms expire in
                  Williams Energy Marketing     2003-2013.
                      and Trading
                  (177 BBtu/d)
                                                Contract terms expire in
                                                2003-2013.
</Table>

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

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

     The ability of our pipeline systems to extend their existing contracts or
re-market expiring capacity with their 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 every attempt is made to
re-negotiate contract terms at fully-subscribed quantities and

                                        5
<PAGE>

at maximum rates allowed under their tariffs, our pipelines must at times
discount their 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 and marketing and trading.

ASSET OWNERSHIP

     Merchant Energy's Asset Ownership activities include ownership interests in
domestic and international power generation, refining and chemicals operations
and coal mining.

     Power Generation.  We own or have interests in 18 power plants in 8
countries. These plants represent 4,242 gross megawatts of generating capacity,
71 percent of which is sold under power purchase or tolling agreements with
terms in excess of five years. Of these facilities, 39 percent are natural gas
fired and 61 percent are a combination of coal, natural gas liquids and other
fuels. Through an affiliate, we have invested in two U.S. power generation
facilities with a total generating capacity of approximately 300 gross
megawatts. Internationally, our focus is on building energy infrastructure in
emerging markets. Our primary areas of focus include Asia and Central America.

     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
REGION                            PROJECT STATUS           FACILITIES   MEGAWATTS   MEGAWATTS(1)
------                            --------------           ----------   ---------   ------------
<S>                       <C>                              <C>          <C>         <C>
United States
  East Coast              Operational...................        4           408          408
  Central                 Operational...................        1         1,500          653
                          Under Construction............        1           544          272
Asia                      Operational...................        6           593          469
Central America           Operational...................        5         1,148          408
                          Under Construction............        1            49           10
                                                               --         -----        -----
          Total.........................................       18         4,242        2,220
                                                               ==         =====        =====
</Table>

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

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

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

     In 2001, our refineries operated at 70 percent of their average combined
capacity and at 93 percent in each of 2000 and 1999. The aggregate sales volumes
at our wholly owned refineries were approximately 131 MMBbls in 2001, 182 MMBbls
in 2000 and 171 MMBbls in 1999. Of our total refinery sales in 2001, 39 percent
was gasoline, 39 percent was middle distillates, such as jet fuel, diesel fuel
and home heating oil, and 22 percent was heavy industrial fuels and other
products.

                                        6
<PAGE>

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

<Table>
<Caption>
                                                        AVERAGE            AT DECEMBER 31,
                                                         DAILY                  2001
                                                       THROUGHPUT        -------------------
                                                  --------------------    DAILY     STORAGE
REFINERY                     LOCATION             2001    2000    1999   CAPACITY   CAPACITY
--------                     --------             ----    ----    ----   --------   --------
                                                                  (IN MBBLS)
<S>                <C>                            <C>     <C>     <C>    <C>        <C>
Aruba              Aruba.......................   178     229     195      280       15,258
Eagle Point        Westville, New Jersey.......   118     143     143      140        8,854
Corpus Christi(1)  Corpus Christi, Texas.......    38      99     100       --           --
Mobile             Mobile, Alabama.............    10      12      13       18          600
                                                  ---     ---     ---      ---       ------
     Total.....................................   344     483     451      438       24,712
                                                  ===     ===     ===      ===       ======
</Table>

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

(1) In June 2001, we leased our Corpus Christi refinery to Valero Energy
    Corporation. The lease is for 20 years, and Valero has an option to purchase
    the refinery beginning in 2003. These volumes only reflect those produced
    prior to our lease of the facilities.

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

<Table>
<Caption>
                                                              2001    2000    1999
                                                              -----   -----   -----
                                                                     (MTONS)
<S>                                                           <C>     <C>     <C>
Industrial..................................................    492     547     608
Agricultural................................................    378     389     326
Gasoline additives..........................................    173     214     209
                                                              -----   -----   -----
          Total.............................................  1,043   1,150   1,143
                                                              =====   =====   =====
</Table>

     Coal Mining.  Our Coal mining business controls reserves totaling 524
million recoverable tons and produces high-quality bituminous coal from reserves
in Kentucky, Virginia and West Virginia. The extracted coal is primarily sold
under long-term contracts to power generation facilities in the eastern U.S.
During the year ended December 31, 2001, coal production totaled 11.5 million
tons.

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

MARKETING AND TRADING

     Merchant Energy's marketing and trading groups trade crude oil, refined
products, coal and other energy commodities and related financial instruments.
Through these activities, these groups attempt to optimize the value of the
segment's asset portfolio.

     Prior to October 2000, we conducted our natural gas and power marketing and
trading activities through Engage Energy US, L.P. and Engage Energy Canada,
L.P., a joint venture between us and Westcoast Energy Inc., a Canadian natural
gas company. During the fourth quarter of 2000, we terminated the Engage joint
venture and assumed the U.S. portion of Engage's trading activities. In February
2001, we transferred our natural gas and power trading activities in the U.S. to
El Paso Merchant Energy, our affiliate and a subsidiary of El Paso, and we
stopped natural gas and power trading activities.

                                        7
<PAGE>

     Detailed below is the marketed and traded energy commodity volumes for each
of the three years ended December 31:

<Table>
<Caption>
                                                           2001      2000      1999
Volumes                                                   -------   -------   -------
<S>                                                       <C>       <C>       <C>
  Physical
     Natural gas (BBtue/d)..............................    3,457     3,457        --
     Power (MMWh).......................................      407     1,923        --
     Crude oil and refined products (MBbls).............  679,489   660,062   659,945
     Coal (MTons).......................................   10,343     9,834     8,980
  Financial settlements (BBtue/d).......................   89,187    52,451    45,136
</Table>

  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 and refining, chemical and petroleum
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 3,600 suppliers and over 5,800 customers around
the world.

     Merchant Energy's trading, marketing, refining, chemicals and power
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;

     - large domestic and foreign utility companies;

     - affiliates of large local distribution companies;

     - affiliates of other interstate and intrastate pipelines;

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

     - independent refining and chemical companies.

                                        8
<PAGE>

     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.

                               PRODUCTION SEGMENT

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

     Production primarily sells its natural gas to third parties through an
affiliate at spot-market prices. It sells its natural gas liquids at market
prices under monthly or long-term contracts and its oil production at posted
prices, subject to adjustments for gravity and transportation. Production
engages in hedging activities on its natural gas and oil production to stabilize
cash flows and reduce the risk of downward commodity price movements on sales of
its production. During 2001, approximately 73 percent of the segment's overall
production was hedged at fixed prices.

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

                                        9
<PAGE>

  Natural Gas and Oil Reserves

     The table below details Production's proved reserves at December 31, 2001.
Information in this table is based on the reserve report dated January 1, 2002,
prepared internally by Production and reviewed by Huddleston & Co., Inc. This
information agrees with estimates of reserves filed with other federal agencies
except for differences of less than 5 percent resulting from actual production,
acquisitions, property sales, necessary reserve revisions and additions to
reflect actual experience. These reserves include 124,158 MMcfe of production
delivery commitments under financing arrangements that extend through 2005.
Total proved reserves on the fields with this dedicated production were
1,981,239 MMcfe.

<Table>
<Caption>
                                                                   NET PROVED RESERVES(1)
                                                           --------------------------------------
                                                           NATURAL GAS    LIQUIDS(2)      TOTAL
                                                           -----------    ----------    ---------
                                                             (MMCF)        (MBBLS)       (MMCFE)
<S>                                                        <C>            <C>           <C>
Production
  United States
     Producing...........................................   1,236,223       51,817      1,547,126
     Non-Producing.......................................     376,918       10,889        442,252
     Undeveloped.........................................   1,744,906       43,958      2,008,654
                                                            ---------      -------      ---------
          Total Proved...................................   3,358,047      106,664      3,998,032
                                                            =========      =======      =========
  Canada
     Producing...........................................     107,843        6,580        147,323
     Non-Producing.......................................      30,255          761         34,821
     Undeveloped.........................................      48,213        3,541         69,459
                                                            ---------      -------      ---------
          Total Proved...................................     186,311       10,882        251,603
                                                            =========      =======      =========
  Other Countries(3)
     Producing...........................................          --           --             --
     Non-Producing.......................................          --           --             --
     Undeveloped.........................................      40,130        7,771         86,756
                                                            ---------      -------      ---------
          Total Proved...................................      40,130        7,771         86,756
                                                            =========      =======      =========
  Worldwide
     Producing...........................................   1,344,066       58,397      1,694,449
     Non-Producing.......................................     407,173       11,650        477,073
     Undeveloped.........................................   1,833,249       55,270      2,164,869
                                                            ---------      -------      ---------
          Total Proved...................................   3,584,488      125,317      4,336,391
                                                            =========      =======      =========

Natural Gas Systems(4)
     Producing...........................................     182,857           97        183,439
     Non-Producing.......................................          --           --             --
     Undeveloped.........................................          --           --             --
                                                            ---------      -------      ---------
          Total Proved...................................     182,857           97        183,439
                                                            =========      =======      =========
</Table>

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

(1)Net proved reserves exclude royalties and interests owned by others and
   reflects contractual arrangements and royalty obligations in effect at the
   time of the estimate.
(2)Includes oil, condensate and natural gas liquids.
(3)Includes international operations in Brazil and Indonesia.
(4)Includes natural gas and oil properties owned by Colorado Interstate Gas
   Company and its subsidiaries. These reserves are located in the U.S.

                                        10
<PAGE>

     There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures, including many factors beyond the control of
Production. The reserve data represents only estimates. Reservoir engineering is
a subjective process of estimating underground accumulations of natural gas and
oil that cannot be measured in an exact manner. The accuracy of any reserve
estimate is a function of the quality of available data and of engineering and
geological interpretations and judgment. As a result, estimates of different
engineers often vary. In addition, results of drilling, testing and production
subsequent to the date of an estimate may justify revision of that estimate.
Reserve estimates are often different from the quantities of natural gas and oil
that are ultimately recovered. The meaningfulness of reserve estimates is highly
dependent on the accuracy of the assumptions on which they were based. In
general, the volume of production from natural gas and oil properties owned by
Production declines as reserves are depleted. Except to the extent Production
conducts successful exploration and development activities or acquires
additional properties containing proved reserves, or both, the proved reserves
of Production will decline as reserves are produced.

     For further discussion of our reserves, see Part II, Item 8, Financial
Statements and Supplementary Data, Note 19.

  Wells and Acreage

     The following table details Production's gross and net interest in
developed and undeveloped onshore, offshore, coal seam and international acreage
at December 31, 2001. Any acreage in which Production's interest is limited to
owned royalty, overriding royalty and other similar interests are excluded.

<Table>
<Caption>
                                       DEVELOPED              UNDEVELOPED                 TOTAL
                                 ---------------------   ----------------------   ----------------------
                                   GROSS        NET        GROSS         NET        GROSS         NET
                                 ---------   ---------   ----------   ---------   ----------   ---------
<S>                              <C>         <C>         <C>          <C>         <C>          <C>
Production
  United States
    Onshore....................  1,727,082     921,212    1,078,670     671,949    2,805,752   1,593,161
    Offshore...................    418,644     256,628      386,746     369,689      805,390     626,317
    Coal Seam..................     27,488       7,449        1,040          22       28,528       7,471
                                 ---------   ---------   ----------   ---------   ----------   ---------
         Total.................  2,173,214   1,185,289    1,466,456   1,041,660    3,639,670   2,226,949
                                 ---------   ---------   ----------   ---------   ----------   ---------
  International
    Australia..................         --          --    1,770,364     613,600    1,770,364     613,600
    Bolivia....................         --          --      154,840      15,484      154,840      15,484
    Brazil.....................         --          --    5,570,315   4,089,259    5,570,315   4,089,259
    Canada.....................    838,300     615,373      290,370     130,528    1,128,670     745,901
    Hungary....................         --          --      568,100     568,100      568,100     568,100
    Indonesia..................         --          --    1,373,691     442,606    1,373,691     442,606
                                 ---------   ---------   ----------   ---------   ----------   ---------
         Total.................    838,300     615,373    9,727,680   5,859,577   10,565,980   6,474,950
                                 ---------   ---------   ----------   ---------   ----------   ---------
         Worldwide Total.......  3,011,514   1,800,662   11,194,136   6,901,237   14,205,650   8,701,899
                                 ---------   ---------   ----------   ---------   ----------   ---------
Natural Gas Systems
  Domestic Onshore.............    262,474     259,276           --          --      262,474     259,276
                                 ---------   ---------   ----------   ---------   ----------   ---------
         Total.................  3,273,988   2,059,938   11,194,136   6,901,237   14,468,124   8,961,175
                                 =========   =========   ==========   =========   ==========   =========
</Table>

     The U.S. domestic net developed acreage is concentrated primarily in Texas
(28 percent), Utah (25 percent), the Gulf of Mexico (18 percent), Colorado (11
percent), West Virginia (9 percent) and Wyoming (7 percent). Approximately 16
percent, 27 percent and 23 percent of our total U.S. net undeveloped acreage is
under leases that have minimum remaining primary terms expiring in 2002, 2003
and 2004.

                                        11
<PAGE>

     The following table details Production's working interests in onshore,
offshore, coal seam and international natural gas and oil wells at December 31,
2001:

<Table>
<Caption>
                                       PRODUCTIVE                                           NUMBER OF
                                      NATURAL GAS       PRODUCTIVE          TOTAL          WELLS BEING
                                         WELLS          OIL WELLS      PRODUCTIVE WELLS      DRILLED
                                     --------------    ------------    ----------------    ------------
                                     GROSS     NET     GROSS    NET    GROSS      NET      GROSS    NET
                                     -----    -----    -----    ---    ------    ------    -----    ---
<S>                                  <C>      <C>      <C>      <C>    <C>       <C>       <C>      <C>
Production
  United States
    Onshore........................  2,479    1,962     469     307    2,948     2,269      35      26
    Offshore.......................    238      125      40      25      278       150      --      --
    Coal Seam......................    278       61      --      --      278        61      --      --
                                     -----    -----     ---     ---    -----     -----      --      --
         Total.....................  2,995    2,148     509     332    3,504     2,480      35      26
                                     -----    -----     ---     ---    -----     -----      --      --
  International
    Canada.........................    305      178     264     122      569       300       7       4
                                     -----    -----     ---     ---    -----     -----      --      --
         Worldwide Total...........  3,300    2,326     773     454    4,073     2,780      42      30
                                     -----    -----     ---     ---    -----     -----      --      --
  Natural Gas Systems
    Domestic Onshore...............    879      806       9       8      888       814      --      --
                                     -----    -----     ---     ---    -----     -----      --      --
         Total.....................  4,179    3,132     782     462    4,961     3,594      42      30
                                     =====    =====     ===     ===    =====     =====      ==      ==
</Table>

     The following table details Production's exploratory and development wells
drilled during the years 1999 through 2001:

<Table>
<Caption>
                                                   NET EXPLORATORY      NET DEVELOPMENT
                                                    WELLS DRILLED        WELLS DRILLED
                                                  ------------------   ------------------
                                                  2001   2000   1999   2001   2000   1999
                                                  ----   ----   ----   ----   ----   ----
<S>                                               <C>    <C>    <C>    <C>    <C>    <C>
Production
  United States
     Productive.................................    9     10      7    183    224    181
     Dry........................................    3      7      5     19     14      1
                                                   --     --     --    ---    ---    ---
       Total....................................   12     17     12    202    238    182
                                                   --     --     --    ---    ---    ---
  Canada
     Productive.................................   12      3      5     47     10      2
     Dry........................................   12      3     --     26      1      2
                                                   --     --     --    ---    ---    ---
       Total....................................   24      6      5     73     11      4
                                                   --     --     --    ---    ---    ---
  Other Countries(1)
     Productive.................................   --     --     --     --     --     --
     Dry........................................    6      1     --      1     --     --
                                                   --     --     --    ---    ---    ---
       Total....................................    6      1     --      1     --     --
                                                   --     --     --    ---    ---    ---
  Worldwide
     Productive.................................   21     13     12    230    234    183
     Dry........................................   21     11      5     46     15      3
                                                   --     --     --    ---    ---    ---
       Total....................................   42     24     17    276    249    186
                                                   --     --     --    ---    ---    ---
Natural Gas Systems
     Productive.................................   --     --     --     17      1     13
     Dry........................................   --     --     --     --     --     --
                                                   --     --     --    ---    ---    ---
       Total....................................   --     --     --     17      1     13
                                                   --     --     --    ---    ---    ---
          Total.................................   42     24     17    293    250    199
                                                   ==     ==     ==    ===    ===    ===
</Table>

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

                                        12
<PAGE>

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

  Net Production, Unit Prices and Production Costs

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

<Table>
<Caption>
                                                             2001      2000      1999
                                                            ------    ------    ------
<S>                                                         <C>       <C>       <C>
Production
    United States
     Net Production:
       Natural Gas (Bcf)..................................     373       328       231
       Oil, Condensate and Liquids (MMBbls)...............       8         6         4
          Total (Bcfe)....................................     422       367       257
     Average Sales Price(1):
       Natural Gas ($/Mcf)................................  $ 4.03    $ 2.83    $ 2.17
       Oil, Condensate and Liquids ($/Bbl)................  $22.43    $24.86    $14.48
     Average Production Cost ($/Mcfe)(2)..................  $ 0.50    $ 0.45    $ 0.40
  Canada
     Net Production:
       Natural Gas (Bcf)..................................      13         1        --
       Oil, Condensate and Liquids (MMBbls)...............       1        --        --
          Total (Bcfe)....................................      17         1        --
     Average Sales Price(1):
       Natural Gas ($/Mcf)................................  $ 2.68    $ 4.09    $   --
       Oil, Condensate and Liquids ($/Bbl)................  $18.26    $   --    $   --
     Average Production Cost ($/Mcfe)(2)..................  $ 0.74    $ 0.66    $   --
  Worldwide
     Net Production:
       Natural Gas (Bcf)..................................     386       329       231
       Oil, Condensate and Liquids (MMBbls)...............       9         6         4
          Total (Bcfe)....................................     439       368       257
     Average Sales Price(1):
       Natural Gas ($/Mcf)................................  $ 3.99    $ 2.83    $ 2.17
       Oil, Condensate and Liquids ($/Bbl)................  $22.16    $24.86    $14.48
     Average Production Cost ($/Mcfe)(2)..................  $ 0.51    $ 0.45    $ 0.40
Natural Gas Systems
     Net Production:
       Natural Gas (Bcf)..................................      30        33        36
     Average Sales Price(1):
       Natural Gas ($/Mcf)................................  $ 3.00    $ 2.06    $ 1.38
</Table>

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

(1) Includes costs associated with transporting volumes sold and the effects of
    our hedging program.
(2) Includes direct lifting costs (labor, repairs and maintenance, materials and
    supplies) and the administrative costs of field offices, insurance and
    property and severance taxes.

                                        13
<PAGE>

  Acquisition, Development and Exploration Expenditures

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

<Table>
<Caption>
                                                            2001      2000      1999
                                                           ------    ------    ------
                       Production                                (IN MILLIONS)
<S>                                                        <C>       <C>       <C>
  United States
     Acquisition Costs:
       Proved............................................  $   87    $  127    $  154
       Unproved..........................................      33       130       142
     Development Costs...................................   1,026       960       588
     Exploration Costs:
       Delay Rentals.....................................       9         6         4
       Seismic Acquisition and Reprocessing..............      10        51        50
       Drilling..........................................      91       136        96
                                                           ------    ------    ------
          Total..........................................  $1,256    $1,410    $1,034
                                                           ======    ======    ======
  Canada
     Acquisition Costs:
       Proved............................................  $  232    $    3    $   --
       Unproved..........................................      16         6        10
     Development Costs...................................     105        69         5
     Exploration Costs:
       Delay Rentals.....................................      --        --        --
       Seismic Acquisition and Reprocessing..............      10        10         5
       Drilling..........................................       9        32         6
                                                           ------    ------    ------
          Total..........................................  $  372    $  120    $   26
                                                           ======    ======    ======
  Other Countries(1)
     Acquisition Costs:
       Proved............................................  $   --    $   --    $   --
       Unproved..........................................      26        --        --
     Development Costs...................................      14        --        --
     Exploration Costs:
       Delay Rentals.....................................      --        --        --
       Seismic Acquisition and Reprocessing..............       6        18         5
       Drilling..........................................      61        14         2
                                                           ------    ------    ------
          Total..........................................  $  107    $   32    $    7
                                                           ======    ======    ======
  Worldwide
     Acquisition Costs:
       Proved............................................  $  319    $  130    $  154
       Unproved..........................................      75       136       152
     Development Costs...................................   1,145     1,029       593
     Exploration Costs:
       Delay Rentals.....................................       9         6         4
       Seismic Acquisition and Reprocessing..............      26        79        60
       Drilling..........................................     161       182       104
                                                           ------    ------    ------
          Total..........................................  $1,735    $1,562    $1,067
                                                           ======    ======    ======
</Table>

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

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

                                        14
<PAGE>

  Regulatory and Operating Environment

     Production's natural gas and oil activities are regulated at the federal,
state and local levels, as well as internationally by the countries around the
world in which Production does business. These regulations include, but are not
limited to, the drilling and spacing of wells, conservation, forced pooling and
protection of correlative rights among interest owners. Production is also
subject to governmental safety regulations in the jurisdictions in which it
operates.

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

     Production's business has operating risks normally associated with the
exploration for and production of natural gas and oil, including blowouts,
cratering, pollution and fires, each of which could result in damage to life or
property. Offshore operations may encounter usual marine perils, including
hurricanes and other adverse weather conditions, governmental regulations and
interruption or termination by governmental authorities based on environmental
and other considerations. Customary with industry practices, we maintain
insurance coverage on behalf of Production with respect to potential losses
resulting from these operating hazards. However, insurance is not available to
Production against all operational risks.

  Markets and Competition

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

                             FIELD SERVICES SEGMENT

     Our Field Services segment provides customers with wellhead-to-mainline
services, including natural gas gathering, products extraction, fractionation,
dehydration, purification, compression and transportation of natural gas and
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
Rocky Mountain region, referred to as the Western Division; in the producing
regions of east and south Texas, referred to as the Central Division; and in
Louisiana, referred to as the Eastern Division.

                                        15
<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...............     100         2,639          319         317      326      182
Western Division...............     100         1,820          435         335      293      424
</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.

<Table>
<Caption>
                                                                             AVERAGE NATURAL GAS
                                                  AVERAGE INLET VOLUME(1)      LIQUIDS SALES(1)
                       OWNERSHIP      INLET       ------------------------   --------------------
  PROCESSING PLANTS    INTEREST    CAPACITY(1)    2001      2000      1999   2001    2000    1999
  -----------------    ---------   ------------   -----   ---------   ----   -----   -----   ----
                       (PERCENT)    (MMCFE/D)            (BBTUE/D)                 (MGAL/D)
<S>                    <C>         <C>            <C>     <C>         <C>    <C>     <C>     <C>
Eastern Division(2)..     100         2,980       1,738     1,606     253    1,619   1,744   331
Western Division.....     100           204         107       105      67      207     201   175
Central Division.....     100           160         135       143     156      343     375   396
Mobile Bay(3)........      42           441         146       338     115       --      --    --
Aux Sable(4).........      14           302         192        --      --       --      --    --
</Table>

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

(1) All volumetric information reflects Field Services' net interest.
(2) Reflects the acquisition of TransCanada Gas Processing U.S.A. in December
    1999.
(3) Mobile Bay went in service in April 1999.
(4) Aux Sable went in service in December 2000.

  Regulatory Environment

     We are subject to the Natural Gas Pipeline Safety Act of 1968, the
Hazardous Liquid Pipeline Safety Act and the National Environmental Policy Act.
We have a continuing program of inspection designed to keep all of the
facilities in compliance with pollution control and pipeline safety
requirements, and we believe 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 or
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 13, and is incorporated
herein by reference.

                                   EMPLOYEES

     As of March 28, 2002, we had approximately 5,000 full-time employees, of
which approximately 650 are subject to collective bargaining agreements.

                                        16
<PAGE>

ITEM 2. PROPERTIES

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

     We believe that we have satisfactory title to the properties owned and used
in our businesses, subject to liens for 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 such
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 13, and is incorporated herein
by reference.

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

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

                                        17
<PAGE>

                                    PART II

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

     On January 29, 2001, we merged with El Paso. As a result of the merger and
the conversion of all of our outstanding common stock and Class A common stock
into El Paso common stock, all of our common stock is owned by El Paso.

ITEM 6. SELECTED FINANCIAL DATA

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

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

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

  Merger with El Paso Corporation

     In January 2001, we merged with El Paso. El Paso accounted for the merger
as a pooling of interests and converted each share of our common stock and Class
A common stock on a tax-free basis into 1.23 shares of El Paso common stock. El
Paso also exchanged our outstanding convertible preferred stock for its common
stock on the same basis as if the preferred stock had been converted into our
common stock immediately prior to the merger. El Paso issued a total of 271
million shares, including 4 million shares issued to holders of our stock
options.

     In connection with a Federal Trade Commission (FTC) order related to this
merger, in 2001 we sold our Gulfstream pipeline project and our investments in
the Empire State, Stingray, U-T Offshore and Iroquois pipeline systems. Proceeds
from these sales were approximately $184 million, and we recognized an
extraordinary loss of $11 million, net of income taxes of $5 million, on these
transactions.

  Merger-Related Costs, Asset Impairments and Other Charges

     Below are the charges incurred that had a significant impact on our results
of operations, financial position and cash flows for the years ended December
31:

<Table>
<Caption>
                                                               2001    2000
                                                              ------   ----
                                                              (IN MILLIONS)
<S>                                                           <C>      <C>
Merger-related costs........................................  $  977   $13
Asset impairments...........................................       9    21
                                                              ------   ---
  Total merger-related costs and asset impairments..........     986    34
Changes in accounting estimates.............................     317    --
                                                              ------   ---
                                                               1,303    34
Ceiling test charges........................................     115    --
                                                              ------   ---
                                                              $1,418   $34
                                                              ======   ===
</Table>

                                        18
<PAGE>

     Merger-Related Costs.  Our merger-related costs relate to our merger with
El Paso and consisted of the following for the years ended December 31:

<Table>
<Caption>
                                                              2001     2000
                                                              -----    -----
                                                              (IN MILLIONS)
<S>                                                           <C>      <C>
Employee severance, retention and transition costs..........  $586      $--
Transaction costs...........................................     7       13
Business and operational integration costs..................   122       --
Merger-related asset impairments............................   162       --
Other.......................................................   100       --
                                                              ----      ---
                                                              $977      $13
                                                              ====      ===
</Table>

     Employee severance, retention and transition costs include direct payments
to, and benefit costs for, severed employees and early retirees that occurred as
a result of our merger-related workforce reduction and consolidation. Following
the merger, El Paso completed an employee restructuring across all of our
operating segments, resulting in the reduction of approximately 3,200 full-time
positions through a combination of early retirements and terminations. Employee
severance costs include actual severance payments and costs for pension and
post-retirement benefits settled and curtailed under existing benefit plans as a
result of these restructurings. Retention charges include payments to employees
who were retained following the mergers and payments to employees to satisfy
contractual obligations. Transition costs relate to costs to relocate employees
and costs for severed and retired employees arising after their severance date
to transition their jobs into the ongoing workforce. The pension and
post-retirement benefits were accrued on the merger date and will be paid over
the applicable benefit periods of the terminated and retired employees. All
other costs were expensed as incurred and have been paid.

     Also included in the 2001 employee severance, retention and transition
costs, was a charge of $278 million resulting from the issuance of approximately
4 million shares of El Paso common stock on the merger date in exchange for the
fair value of our employees' and directors' stock options.

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

     Business and operational integration costs include charges to consolidate
facilities and operations of our business segments, such as lease termination
and abandonment charges, recognition of the mark-to-market value of energy
trading contracts resulting from changes in how these contracts are managed
under the El Paso combined operating strategy and incremental fees under
software and seismic license agreements. Also included in the 2001 charges are
approximately $121 million in estimated lease related costs to relocate our
pipeline operations from Detroit, Michigan to Houston, Texas. These charges were
accrued at the time we completed our relocations and closed this office. The
amounts accrued will be paid over the term of the applicable non-cancelable
lease agreements. All other costs were expensed as incurred.

     Merger-related asset impairments relate to write-offs or write-downs of
capitalized costs for duplicate systems, redundant facilities and assets whose
value was impaired as a result of decisions on the strategic direction of our
combined operations following the merger. These charges occurred in our Merchant
Energy, Production and Pipelines segments, and all of these assets have either
had their operations suspended or continue to be held for use. The charges taken
were based on a comparison of the cost of the assets to their estimated fair
value to the ongoing operations based on this change in operating strategy.

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

     Asset Impairments. The 2001 asset impairment charges resulted from the
write-down of Merchant Energy's Corpus Christi refinery and related assets as a
result of our lease of these assets to Valero in June 2001. The 2000 charges
consisted of the impairment of coal mining and refining assets in our Merchant

                                        19
<PAGE>

Energy segment. These impairments 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 operation has been suspended.

     Changes in Accounting Estimates. Our 2001 changes in accounting estimates
consist of $232 million in additional environmental remediation liabilities, $47
million of additional accrued legal obligations and a $38 million charge to
reduce the value of our spare parts inventories to reflect changes in the
usability of these parts in our worldwide operations. These changes were
primarily the result of several events that occurred as part of and following
our merger with El Paso, including the consolidation of numerous operating
locations, the sale of a majority of our retail gas stations, the shutdown of
our Midwest refining operations and the lease of our Corpus Christi refinery.
These changes were also a direct result of a fire at our Aruba refinery. Also
impacting these amounts was the evaluation of the operating standards,
strategies and plans of our combined company following the merger. These charges
are included as operating expenses in our income statement and reduced our net
income before extraordinary items and net income for the year ended December 31,
2001, by approximately $241 million.

     Ceiling Test Charges. Under the full cost method of accounting for natural
gas and oil properties, we perform quarterly ceiling tests to evaluate whether
the carrying value of natural gas and oil properties exceeds the present value
of future net revenues, discounted at 10 percent, plus the lower of cost or fair
market value of unproved properties. During the third quarter of 2001,
capitalized costs exceeded this ceiling limit by $115 million, including $87
million for our Canadian full cost pool and $28 million for our Brazilian full
cost pool. These charges were based on the November 1, 2001 daily posted oil and
natural gas sales prices, adjusted for oilfield or gas gathering hub and
wellhead price differences as appropriate. This non-cash write-down is included
in our income statement as ceiling test charges.

     We use financial instruments to hedge against volatility of natural gas and
oil prices. The impact of these hedges was considered in the determination of
our ceiling test charge during 2001 and will be factored into future ceiling
test calculations. Had the impact of our hedges not been included in calculating
our 2001 ceiling test charge, the charge would not have materially changed since
we do not significantly hedge our international production activities.

     Also as mentioned above, our 2001 charge was computed based on daily posted
prices on November 1, 2001. Had we computed this charge based on the daily oil
and natural gas prices as of September 30, 2001, the charge would have been
approximately $255 million, including approximately $227 million for our
Canadian full cost pool and $28 million for our Brazilian full cost pool,
including the impact on future cash flows of our hedging program. Had the impact
of our hedging program been excluded, the charges would have been approximately
the same for our international full cost pools and production operations, but we
would have incurred an additional charge of approximately $830 million related
to our U.S. full cost pool.

                             RESULTS OF OPERATIONS

     For the year ended December 31, 2001, we had a net loss of $188 million
versus net income of $654 million for the year ended December 31, 2000. The 2001
loss was a result of the charges discussed above which totaled $1,418 million,
or $1,181 million after taxes. We also recorded net extraordinary losses
totaling $11 million, net of income taxes, as a result of FTC ordered sales of
our Gulfstream pipeline project and our investments in the Empire State,
Stingray, U-T Offshore and Iroquois pipeline systems. For the year ended
December 31, 2000, merger-related charges were $34 million, or $24 million net
of income taxes. Net income, excluding the after-tax effects of these charges
and extraordinary items, would have been $1,004 million in 2001 versus $678
million in 2000.

                                        20
<PAGE>

                                SEGMENT RESULTS

     Our four segments: Pipelines, Merchant Energy, Production and Field
Services are strategic business units that offer a variety of different energy
products and services, each requiring different technology and marketing
strategies. We evaluate our segment performance based on EBIT. Our historical
segments (natural gas systems; refining, marketing and chemicals; exploration
and production; power; and coal) have been restated and included in the segments
in which these businesses were managed and operated following the merger. All
prior periods have been restated to reflect this presentation. The results
presented in this analysis are not necessarily indicative of the results that
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 trading and refining
portions of Merchant Energy and for the Field Services segment. 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 15.

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

<Table>
<Caption>
                                                               2001       2000
                                                              ------     ------
                                                                (IN MILLIONS)
<S>                                                           <C>        <C>
Pipelines...................................................  $  292     $  500
Merchant Energy.............................................     (11)       366
Production..................................................     791        413
Field Services..............................................      71        111
                                                              ------     ------
  Segment EBIT..............................................   1,143      1,390
                                                              ------     ------
Corporate and other, net....................................    (698)        78
                                                              ------     ------
  Consolidated EBIT.........................................  $  445     $1,468
                                                              ======     ======
</Table>

PIPELINES

     Our Pipelines segment operates our interstate pipeline businesses. Each
pipeline system operates under a separate tariff that governs its 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 system to system, 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 the years ended December 31:

<Table>
<Caption>
                                                                2001        2000
                                                              --------     -------
                                                              (IN MILLIONS, EXCEPT
                                                                VOLUME AMOUNTS)
<S>                                                           <C>          <C>
Operating revenues..........................................  $ 1,052      $1,045
Operating expenses..........................................     (860)       (657)
Other income................................................      100         112
                                                              -------      ------
  EBIT......................................................  $   292      $  500
                                                              =======      ======
Throughput volumes (BBtu/d)(1)..............................    7,443       7,167
                                                              =======      ======
</Table>

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

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

                                        21
<PAGE>

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

     Operating revenues for the year ended December 31, 2001, were $7 million
higher than the same period in 2000. The increase was due to the impact of
completed system expansions and new storage and transportation contracts during
2001, higher realized prices on segment-owned production and on sales of natural
gas purchased from the Dakota gasification facility. Also contributing to the
increase was increased fuel recoveries due to higher natural gas prices and
increased fuel efficiencies. Partially offsetting the increase was the favorable
resolution of natural gas price-related contingencies in 2000, lower 2001 sales
of base gas from abandoned storage fields and the favorable resolution of
regulatory issues in 2000.

     Operating expenses for the year ended December 31, 2001, were $203 million
higher than the same period in 2000. The increase was primarily the result of
merger-related costs and other charges in 2001 discussed previously, along with
the impact of higher natural gas prices on system fuel costs and gas purchases
at the Dakota gasification facility. Also contributing to the increase were
higher corporate allocations. Partially offsetting the increase was lower
purchase gas costs due to the net impact of a natural gas imbalance revaluation
in 2001 as a result of falling gas prices during the second half of the year and
accruals for the replacement of system balancing gas in 2000.

     Other income for the year ended December 31, 2001, was $12 million lower
than the same period in 2000. The decrease was due to lower equity income in
2001 on the ANR Storage project and the sales of our investments in the Empire
State and Iroquois pipeline systems in the first and second quarters of 2001.
Also contributing to the decrease were higher expenses in 2001 related to
expansion and development projects and a tax refund in the fourth quarter of
2000. Partially offsetting the decrease were increased earnings from our
investments in the Alliance Pipeline project and the Great Lakes Gas
Transmission project.

MERCHANT ENERGY

     Our Merchant Energy segment is involved in asset ownership and marketing
and trading. The markets served by Merchant Energy are highly competitive and
influenced directly or indirectly by energy market economics.

  Asset Ownership

     Merchant Energy's asset ownership activities include domestic and
international power plants and refining, chemical and coal mining operations. In
its power asset business, Merchant Energy owns or has interests in 18 plants in
8 countries. Merchant Energy also has refining, chemical and coal mining
operations. Results from Merchant Energy's refining and chemical operations are
highly dependent on margin differentials between feedstocks, primarily crude oil
and other petroleum products and market prices of the products produced, both of
which can be highly volatile. In our coal mining business, results are driven by
productivity of our mining operations along with the market prices of the coal
produced.

  Marketing and Trading

     Merchant Energy's marketing and trading activities trade crude oil, refined
products, coal and other energy commodities and related financial instruments.
At December 31, 2001, the fair value of our trading-related price risk
management activities was a net unrealized loss of $23 million, and total
margins generated from these activities during 2001 were $15 million.

     Prior to October 2000, we conducted our natural gas and power marketing and
trading activities through Engage Energy U.S., L.P. and Engage Canada, L.P., a
joint venture between us and Westcoast Energy Inc., a major Canadian natural gas
company. During the fourth quarter of 2000, we terminated the Engage joint
venture and assumed Engage's U.S. trading activities. In February 2001, we
transferred these activities to a subsidiary of El Paso in exchange for a 22
percent interest in El Paso Merchant Energy, L.P.

                                        22
<PAGE>

     Below are Merchant Energy's operating results and traded volumes (excluding
intrasegment transactions) and an analysis of these results for the years ended
December 31:

<Table>
<Caption>
                                                                2001        2000
                                                              ---------   ---------
                                                              (IN MILLIONS, EXCEPT
                                                                    VOLUMES)
<S>                                                           <C>         <C>
Operating results:
Trading and refining gross margin...........................  $    865    $    952
Operating and other revenues................................       321         330
Operating expenses..........................................    (1,396)     (1,164)
Other income................................................       199         248
                                                              --------    --------
  EBIT......................................................  $    (11)   $    366
                                                              ========    ========
</Table>

<Table>
<S>                                                           <C>        <C>
     Volumes (Excludes intrasegment transactions):
     Physical
       Natural gas (BBtue/d)................................     3,457      3,457
       Power (MMWh).........................................       407      1,923
       Crude oil and refined products (MBbls)...............   679,489    660,062
       Coal (MTons).........................................    10,343      9,834
     Financial Settlements (BBtue/d)........................    89,187     52,451
</Table>

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

     Trading and refining gross margin consists of revenues from our refineries
and commodity trading activities, less the costs of the feedstocks used in the
refining process and the costs of commodities sold. For the year ended December
31, 2001, our trading and refining gross margin was $87 million lower than the
same period in 2000. This decrease was primarily due to lower refining margins
resulting from a fire at our Aruba facility in April 2001, the lease of our
Corpus Christi refinery and related assets to Valero in June 2001, lower margins
in heavy crude based refined products and lower margins and throughput at the
Eagle Point refinery as a result of decreased demand for jet fuel following the
events of September 11, 2001. The decrease in refining margins resulting from
the fire at our Aruba facility was largely offset by the collection of business
interruption insurance proceeds.

     Operating and other revenues consist of revenues from consolidated domestic
power generation facilities and coal operations. For the year ended December 31,
2001, operating and other revenues were $9 million lower than the same period in
2000. The decrease resulted primarily from the transfer of power index swaps on
our Fulton and Rensselaer power facilities to a subsidiary of El Paso in
February 2001, partially offset by increased coal volumes.

     Operating expenses for the year ended in December 31, 2001, were $232
million higher than the same period in 2000. The increase was primarily a result
of merger-related costs and asset impairments associated with combining
operations and implementing our combined strategy with El Paso, and changes in
our estimates of environmental remediation costs, legal obligations and spare
parts inventory usability. The increase also resulted from higher fuel costs at
our refineries due to higher natural gas prices. These increases were partially
offset by lower operating expenses resulting from the lease of our Corpus
Christi refinery and related assets to Valero in June 2001.

     Other income for the year ended December 31, 2001, was $49 million lower
than the same period in 2000. The decrease was the result of the sale of our
interest in a Guatemala power project in the first quarter of 2000, lower
earnings from the Javelina project in 2001 due to lower NGL prices and higher
gas costs and a gain recorded in 2000 from the sale of 49 percent of our
Montreal petrochemical facility. These decreases were partially offset by higher
equity earnings from a power facility investment due to the completion of a
power purchase contract restructuring in the fourth quarter 2001.

                                        23
<PAGE>

PRODUCTION

     Production's operating results are driven by a variety of factors including
its ability to locate and develop economic natural gas and oil reserves, extract
those reserves with minimal production costs, sell the products at attractive
prices and operate at the lowest cost level possible. In 2002, Production
expects to continue an active onshore and offshore development drilling program
to capitalize on its land and seismic holdings. The estimated capital
expenditures for Production in 2002 are $1.2 billion. Production will continue
to pursue strategic acquisitions of production properties and the development of
coal seam projects subject to acceptable return hurdles.

     Production engages in hedging activities on its natural gas and oil
production in order to stabilize cash flows and reduce the risk of downward
commodity price movements on sales of its production. This is achieved primarily
through natural gas and oil swaps. During 2001, approximately 73 percent of the
segment's overall production was hedged at fixed prices. Our hedging program is
intended to hedge approximately 75 percent of our anticipated current year
production, approximately 50 percent of our anticipated succeeding year
production and a lesser percentage thereafter. Production's hedge positions are
monitored and evaluated in an effort to achieve its earnings objectives and
reduce the risks associated with spot-market price volatility.

     In December 2001, El Paso announced the potential sale of natural gas and
oil properties. See a discussion of the plan in Part II, Item 8, Financial
Statements and Supplementary Data, Note 1.

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

<Table>
<Caption>
                                                                  2001            2000
                                                              -------------   -------------
                                                              (IN MILLIONS, EXCEPT VOLUMES
                                                                       AND PRICES)
<S>                                                           <C>             <C>
Operating Results:
Natural gas.................................................    $   1,562       $     956
Oil, condensate and liquids.................................          200             162
Other.......................................................           21              13
                                                                ---------       ---------
          Total operating revenues..........................        1,783           1,131
Transportation and net product costs........................          (56)            (46)
                                                                ---------       ---------
          Total operating margin............................        1,727           1,085
Operating expenses..........................................         (942)           (668)
Other income (loss).........................................            6              (4)
                                                                ---------       ---------
  EBIT......................................................    $     791       $     413
                                                                =========       =========
Volumes and Prices:
  Natural gas
     Volumes (MMcf).........................................      385,793         329,071
                                                                =========       =========
     Average realized prices ($/Mcf)........................    $    3.99       $    2.83
                                                                =========       =========
  Oil, condensate and liquids
     Volumes (MBbls)........................................        8,787           6,489
                                                                =========       =========
     Average realized prices ($/Bbl)........................    $   22.16       $   24.86
                                                                =========       =========
</Table>

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

     Operating revenues for the year ended December 31, 2001, were $652 million
higher than the same period in 2000. The increase was attributable to higher
volumes and higher realized prices for natural gas and higher volumes for oil,
condensate and liquids than in 2000.

     Transportation and net product costs for the year ended December 31, 2001,
were $10 million higher than the same period in 2000 primarily due to higher
transported volumes and costs incurred to meet minimum payments on pipeline
agreements.

                                        24
<PAGE>

     Operating expenses for the year ended December 31, 2001, were $274 million
higher than the same period in 2000. The increase was due to full cost ceiling
test charges of $115 million on international properties incurred in the third
quarter of 2001, higher depletion expense in 2001 as a result of increased
production volumes combined with higher capitalized costs in the full cost pool
and merger-related costs. Also contributing to the increase were higher
severance and other production taxes in 2001, which are generally tied to
natural gas and oil prices, and higher oilfield services costs.

     Other income for the year ended December 31, 2001, was $10 million higher
than the same period in 2000. The increase was primarily due to equity earnings
from our investment in an El Paso affiliate. In June 2001, we contributed
natural gas and oil properties to an affiliate in exchange for an equity
investment and began recording equity earnings following the transfer. This
transfer was accounted for at historical cost since the transfer was between
entities under common control.

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 ethane, propane and butane.

     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 its operations earn margins from
market-based rates. Revenues from these market-based rate services are the
product of the market price, usually related to the monthly natural gas price
index and the volume gathered.

     Processing and fractionation operations earn a margin based on fixed-fee
contracts, percentage-of-proceeds contracts and make-whole contracts.
Percentage-of-proceeds contracts allow us to retain a percentage of the product
as a fee for processing or fractionation service. Make-whole contracts allow us
to retain the extracted liquid products and return to the producer a Btu
equivalent amount of natural gas. Under our percentage-of-proceeds contracts and
make-whole contracts, Field Services may have more sensitivity to price changes
during periods when natural gas and natural gas liquids prices are volatile.

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

<Table>
<Caption>
                                                                2001         2000
                                                              --------     --------
                                                              (IN MILLIONS, EXCEPT
                                                               VOLUMES AND PRICES)
<S>                                                           <C>          <C>
Gathering, treating and processing gross margin.............   $  155       $  188
Operating expenses..........................................     (100)        (102)
Other income................................................       16           25
                                                               ------       ------
  EBIT......................................................   $   71       $  111
                                                               ======       ======
Volumes and prices
  Gathering and treating
     Volumes (BBtu/d).......................................      843          934
                                                               ======       ======
     Prices ($/MMBtu).......................................   $ 0.15       $ 0.14
                                                               ======       ======
  Processing
     Volumes (inlet BBtu/d).................................    1,966        1,864
                                                               ======       ======
     Prices ($/MMBtu).......................................   $ 0.14       $ 0.17
                                                               ======       ======
</Table>

                                        25
<PAGE>

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

     Total gross margin for the year ended December 31, 2001, was $33 million
lower than the same period in 2000. The decrease was a result of lower natural
gas liquids prices and volumes in 2001 and lower gathering and treating volumes
in 2001 due to natural declines in production volumes in our operating regions.

     Operating expenses for the year ended December 31, 2001, were $2 million
lower than the same period in 2000. The decrease was due to lower operating and
maintenance expenses due to cost savings following the merger. The decrease was
partially offset by merger-related costs and other charges arising from the
combined operations with El Paso, higher depreciation expense due to plant
additions and capital expenditures and higher ad valorem and other taxes.

     Other income for the year ended December 31, 2001, was $9 million lower
than the same period in 2000. The decrease was primarily due to equity
investment losses from our Mobile Bay and Aux Sable liquids processing
facilities due to lower natural gas liquid prices, lower 2001 equity earnings
from Deepwater Holdings as a result of the sale of our interest to El Paso
Energy Partners L.P., our affiliate, in October 2001 and higher miscellaneous
expenses in 2001. Partially offsetting the decrease was a gain on the sale of
this investment.

CORPORATE AND OTHER EXPENSES, NET

     Corporate and other consists of miscellaneous general and administrative
activities, as well as our retail operations, most of which were sold in 2001.
Corporate expenses for the year ended December 31, 2001, were $776 million
higher than the same period in 2000. The increase was primarily a result of
merger-related charges in connection with our January 2001 merger with El Paso,
costs associated with increased estimates of environmental remediation costs,
legal obligations and usability of spare parts inventories, and lower retail
margins due to the sale of substantially all of our retail gas stations in 2001.

NON-AFFILIATED AND AFFILIATED INTEREST AND DEBT EXPENSE

     Total interest and debt expense for the year ended December 31, 2001, was
$9 million lower than the same period in 2000 primarily due to retirement of
non-affiliated short-term borrowings, consisting of approximately $1 billion of
commercial paper and short-term bank credit facilities. This decrease was
partially offset by increased affiliated interest when these debt instruments
were replaced with advances from El Paso in the second quarter of 2001.

MINORITY INTEREST

     Minority interest for the year ended December 31, 2001, was $9 million
lower than the same period in 2000 primarily due to lower market interest rates.
Our minority interest returns are primarily based on the London Interbank
Offered Rate (LIBOR).

INCOME TAX EXPENSE

     Income tax expense for the year ended December 31, 2001, was $78 million.
This amount includes $106 million related to non-deductible merger charges and
changes in our estimate of additional tax liabilities. The majority of these
estimated additional liabilities were paid in 2001 and are being contested by
us. The effective tax rate excluding these charges was 28 percent. For the year
ended December 31, 2000 income tax expense was $252 million resulting in an
effective tax rate of 28 percent. Differences in our effective tax rates from
the statutory tax rate of 35 percent in all years were primarily a result of the
following factors:

     - state income taxes;

     - foreign income taxed at different rates;

     - depreciation, depletion and amortization;

                                        26
<PAGE>

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

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

     For a reconciliation of the statutory rate of 35 percent to the effective
rates, see Item 8, Financial Statements and Supplementary Data, Note 6.

NEW ACCOUNTING PRONOUNCEMENTS 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.

     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 $19 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.

     In December 2001, El Paso announced a plan under which we may sell a
variety of assets, including natural gas and oil properties and refining,
chemical, coal mining and power assets. Should these sales occur, based on our
current assessment of SFAS No. 144's provisions, our coal mining, chemical and
refining assets are likely to qualify as discontinued operations under the
standard. In addition, SFAS No. 144 establishes new rules when a company begins
to take action to either dispose of, or otherwise alter the manner of operation
of, an asset. Under these new rules, when it becomes "more likely than not" that
a company will alter its current operating plans, an evaluation of possible
impairment is made. Based on our actions to date, we are currently evaluating
whether the assets we may sell are impaired under this standard. Based on
preliminary indications
                                        27
<PAGE>

of market value, coupled with the near-term outlook for the refining and coal
mining industries, we anticipate that we may be required to write-down the
carrying values of the refining and coal mining assets we may sell by an amount
that could range from $145 million to $240 million after-tax under this
standard. We continue to evaluate these and the other assets that may be sold as
part of our plan.

     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.

OTHER

     In August 2001, we completed the acquisition of Velvet Exploration Ltd., at
a cost of approximately $230 million (approximately C$353 million) plus the
assumption of $52 million (approximately C$80 million) in debt. Velvet is a
Canadian exploration and development company, with a majority of its properties
located in the Foothills and Deep Basin areas of western Alberta Province. The
acquisition provides us with a strong platform to build a successful production
business in western Canada by utilizing the expertise of Velvet's high quality
workforce and its inventory of drilling prospects. The acquisition was accounted
for as a purchase and resulted in an excess purchase price of $61 million
(approximately C$97 million) that has been reflected as goodwill. We had other
direct transaction costs and professional fees of $3 million (approximately C$4
million).

COMMITMENTS AND CONTINGENCIES

     For a discussion of our commitments and contingencies, see Item 8,
Financial Statements and Supplementary Data, Note 13, and is incorporated herein
by reference.

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
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 and interest rates. Our primary market risk exposures
are to changing commodity prices. Our market risks are monitored by a corporate
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.

TRADING COMMODITY PRICE RISK

     Prior to October 2000, we conducted our natural gas and power marketing and
trading activities through Engage Energy U.S., L.P. and Engage Canada, L.P., a
joint venture between us and Westcoast Energy Inc., a major Canadian natural gas
company. During the fourth quarter of 2000, we terminated the Engage joint
venture and assumed Engage's U.S. trading activities. In February 2001, we
transferred these activities to a subsidiary of El Paso. Our remaining trading
price risk management activities were insignificant in 2001.

NON-TRADING COMMODITY PRICE RISK

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

     - exchange-traded futures contracts involving cash settlements;

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

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

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

     The table below presents the hypothetical sensitivity to changes in fair
values arising from immediate selected potential changes in the quoted market
prices of the derivative commodity instruments we use to mitigate these market
risks that were outstanding at December 31, 2001 and 2000. Any gain or loss on
these derivative commodity instruments would be substantially offset by a
corresponding gain or loss on the hedged commodity positions, which are not
included in the table.

<Table>
<Caption>
                                                      10% INCREASE         10% DECREASE
                                                   ------------------   ------------------
                                         FAIR      FAIR     INCREASE    FAIR     INCREASE
                                         VALUE     VALUE   (DECREASE)   VALUE   (DECREASE)
                                       ---------   -----   ----------   -----   ----------
<S>                                    <C>         <C>     <C>          <C>     <C>
Impact of changes in commodity prices
  on derivative commodity instruments
  (in millions)
  December 31, 2001..................    $ 501     $ 312     $(180)     $ 658      $166
  December 31, 2000..................    $(665)    $(785)    $(120)     $(545)     $120
</Table>

     In December 2001, we began measuring the risk associated with our commodity
contracts held for non-trading purposes on a daily basis using the historical
simulation technique of measuring Value-at-Risk to determine the maximum
potential one-day unfavorable impact on our earnings, due to normal market
movement and began monitoring our risk in comparison to established thresholds.
This technique uses historical price movements and specific, defined
mathematical parameters to estimate the characteristics of and the relationships
between components of our assets and liabilities held for price risk management

                                        29
<PAGE>

activities. Based on a confidence level of 95 percent and a one-day holding
period, our estimated potential one-day unfavorable impact on earnings before
interest and income taxes was $8 million at December 31, 2001.

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.

     As of December 31, 2001, we maintained an interest rate swap transaction
with a notional amount of $240 million exchanging LIBOR, a variable interest
rate, for a fixed rate of 3.07%. This transaction results in the payment of a
fixed rate of 4.49% until the swap terminates in June 2003. The fair value of
this swap was immaterial as of December 31, 2001.

     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 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    FAIR
                                         2002    2003   2004   2005   2006   THEREAFTER   TOTAL    FAIR VALUE   AMOUNTS    VALUE
                                        ------   ----   ----   ----   ----   ----------   ------   ----------   --------   ------
                                                                    (IN MILLIONS)
<S>                                     <C>      <C>    <C>    <C>    <C>    <C>          <C>      <C>          <C>        <C>
LIABILITIES:
Short-term debt -- variable rate......  $   33                                            $   33     $   33      $  798    $  798
      Average interest rate...........     2.4%
Long-term debt, including current
  portion -- fixed rate...............  $  252   $102   $694   $182   $501     $2,634     $4,365     $4,352      $4,400    $4,501
      Average interest rate...........     8.1%   9.7%   6.9%  10.1%   7.2%       7.7%
Long-term debt, including current
  portion -- variable rate............  $1,058   $275   $296   $128   $262     $   33     $2,052     $2,052      $1,893    $1,912
      Average interest rate...........     2.7%   5.1%   6.1%   6.0%   6.2%       5.6%
Notes payable to unconsolidated
  affiliates -- variable rate.........  $   67                                            $   67     $   67      $   --    $   --
      Average interest rate...........     4.9%
COMPANY-OBLIGATED PREFERRED
  SECURITIES:
Coastal Finance I.....................                                         $  300     $  300     $  299      $  300    $  293
      Average fixed interest rate.....                                            8.4%
</Table>

                                        30
<PAGE>

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                              EL PASO CGP COMPANY

                       CONSOLIDATED STATEMENTS OF INCOME
                                 (IN MILLIONS)

<Table>
<Caption>
                                                                YEAR ENDED DECEMBER 31,
                                                              ---------------------------
                                                               2001      2000      1999
                                                              -------   -------   -------
<S>                                                           <C>       <C>       <C>
Operating revenues..........................................  $25,706   $26,936   $16,596
Operating expenses
  Cost of natural gas and other products....................   21,920    23,552    14,037
  Operation and maintenance.................................    1,663     1,500     1,224
  Merger-related costs and asset impairments................      986        34        --
  Ceiling test charges......................................      115        --        --
  Depreciation, depletion and amortization..................      729       657       493
  Taxes, other than income taxes............................      181       140        99
                                                              -------   -------   -------
                                                               25,594    25,883    15,853
                                                              -------   -------   -------
Operating income............................................      112     1,053       743
                                                              -------   -------   -------
Other income
  Earnings from unconsolidated affiliates...................      223       265       190
  Other, net................................................      110       150        95
                                                              -------   -------   -------
                                                                  333       415       285
                                                              -------   -------   -------
Income before interest, income taxes and other charges......      445     1,468     1,028
                                                              -------   -------   -------
Non-affiliated interest and debt expense....................      447       502       323
Affiliated interest expense, net............................       46        --        --
Minority interest...........................................       51        60        32
Income taxes................................................       78       252       174
                                                              -------   -------   -------
                                                                  622       814       529
                                                              -------   -------   -------
Income (loss) before extraordinary items....................     (177)      654       499
Extraordinary items, net of income taxes....................      (11)       --        --
                                                              -------   -------   -------
Net income (loss)...........................................  $  (188)  $   654   $   499
                                                              =======   =======   =======
</Table>

                            See accompanying notes.

                                        31
<PAGE>

                              EL PASO CGP COMPANY

                          CONSOLIDATED BALANCE SHEETS
                                 (IN MILLIONS)

<Table>
<Caption>
                                                                DECEMBER 31,
                                                              -----------------
                                                               2001      2000
                                                              -------   -------
<S>                                                           <C>       <C>
                                    ASSETS
Current assets
  Cash and cash equivalents.................................  $   131   $    53
  Accounts and notes receivable, net of allowance of $36 in
     2001 and $19 in 2000
     Customer...............................................    1,821     2,549
     Affiliates.............................................      546        88
     Other..................................................      211       388
  Inventory.................................................      693     1,167
  Assets from price risk management activities..............      425       580
  Other.....................................................      357       223
                                                              -------   -------
          Total current assets..............................    4,184     5,048
Property, plant and equipment, at cost
  Pipelines.................................................    6,558     6,092
  Refining, crude oil and chemical facilities...............    2,425     2,338
  Power facilities..........................................      271       237
  Natural gas and oil properties, at full cost..............    7,765     5,100
  Gathering and processing systems..........................      428       340
  Other.....................................................      516       744
                                                              -------   -------
                                                               17,963    14,851
  Less accumulated depreciation, depletion and
     amortization...........................................    5,945     4,248
                                                              -------   -------
          Total property, plant and equipment, net..........   12,018    10,603
                                                              -------   -------
Other assets
  Investments in unconsolidated affiliates..................    1,883     1,613
  Assets from price risk management activities..............      267       138
  Other.....................................................      714     1,473
                                                              -------   -------
                                                                2,864     3,224
                                                              -------   -------
          Total assets......................................  $19,066   $18,875
                                                              =======   =======
</Table>

                            See accompanying notes.

                                        32
<PAGE>
                              EL PASO CGP COMPANY

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

<Table>
<Caption>
                                                                DECEMBER 31,
                                                              -----------------
                                                               2001      2000
                                                              -------   -------
<S>                                                           <C>       <C>
                     LIABILITIES AND STOCKHOLDER'S EQUITY

Current liabilities
  Accounts payable
     Trade..................................................  $ 1,858   $ 1,804
     Affiliates.............................................    1,360        13
     Other..................................................      360     1,403
  Short-term borrowings and other financing obligations.....    1,410     1,094
  Liabilities from price risk management activities.........      213       546
  Other.....................................................      600       348
                                                              -------   -------
          Total current liabilities.........................    5,801     5,208
                                                              -------   -------
Debt
  Long-term debt and other financing obligations............    5,107     5,997
                                                              -------   -------
Other
  Liabilities from price risk management activities.........        1       113
  Deferred income taxes.....................................    1,740     1,956
  Other.....................................................      553       300
                                                              -------   -------
                                                                2,294     2,369
                                                              -------   -------
Commitments and contingencies
Securities of subsidiaries
  Company-obligated preferred securities of consolidated
     trusts.................................................      300       300
  Minority interests........................................      594       451
                                                              -------   -------
                                                                  894       751
                                                              -------   -------
Stockholder's equity
  Cumulative preferred stock, no shares outstanding in 2001;
     with aggregate liquidation preference of $7.3 million
     at December 31, 2000...................................       --        --
  Class A common stock, no shares outstanding in 2001; par
     value 33 1/3c, 311,377 shares issued in 2000...........       --        --
  Common stock, par value $1 per share; 1,000 shares
     authorized and issued in 2001; par value 33 1/3c per
     share, 219,604,836 shares issued in 2000...............       --        73
  Additional paid-in capital................................    1,305     1,044
  Retained earnings.........................................    3,385     3,573
  Accumulated other comprehensive income....................      280        (8)
  Treasury stock (at cost); no shares in 2001 and 4,394,651
     shares in 2000.........................................       --      (132)
                                                              -------   -------
          Total stockholder's equity........................    4,970     4,550
                                                              -------   -------
          Total liabilities and stockholder's equity........  $19,066   $18,875
                                                              =======   =======
</Table>

                            See accompanying notes.

                                        33
<PAGE>

                              EL PASO CGP COMPANY

                     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 (loss).........................................  $  (188)  $   654   $   499
  Adjustments to reconcile net income (loss) to net cash
    from operating activities
    Depreciation, depletion and amortization................      729       657       493
    Ceiling test charges....................................      115        --        --
    Deferred income tax expense (benefit)...................      (38)      203       112
    Extraordinary items.....................................        6        --        --
    Undistributed earnings of unconsolidated affiliates.....      (96)       (3)      (39)
    Non-cash portion of merger-related costs, asset
     impairments and changes in estimates...................    1,180        --        --
    Net gain on the sale of assets..........................       (6)      (18)       --
    Working capital changes, net of non-cash transactions
      Accounts and notes receivable.........................     (296)     (485)     (809)
      Accounts payable/receivable with affiliates...........     (131)       --        --
      Inventory.............................................      422      (137)     (269)
      Change in price risk management activities, net.......       67       (29)       --
      Accounts payable......................................      382       188       578
      Other working capital changes.........................     (376)       75       192
    Non-working capital changes and other...................      182        34         9
                                                              -------   -------   -------
         Net cash provided by operating activities..........    1,952     1,139       766
                                                              -------   -------   -------
Cash flows from investing activities
  Additions to property, plant and equipment................   (2,301)   (2,112)   (1,781)
  Additions to investments..................................     (386)     (286)     (379)
  Cash paid for acquisitions, net of cash acquired..........     (232)       --        --
  Net proceeds from the sale of assets......................      268        59        37
  Proceeds from the sale of investments.....................      363        59        10
  Repayment of notes receivable from unconsolidated
    affiliates..............................................      273        --        --
  Other.....................................................        1        (1)       (3)
                                                              -------   -------   -------
         Net cash used in investing activities..............   (2,014)   (2,281)   (2,116)
                                                              -------   -------   -------
Cash flows from financing activities
  Net borrowings (repayments) of commercial paper and
    short-term credit facilities............................     (765)      217        94
  Payments to retire long-term debt and other financing
    obligations.............................................     (608)     (738)     (487)
  Net proceeds from the issuance of long-term debt and other
    financing obligations...................................      490     1,722     1,345
  Issuances of common stock.................................        2        31        15
  Dividends paid............................................      (13)      (54)      (54)
  Net proceeds from issuance of minority interests in
    subsidiaries............................................      139        --       350
  Net change in other affiliated advances payable...........      889        --        --
  Other.....................................................        6        --        --
                                                              -------   -------   -------
         Net cash provided by financing activities..........      140     1,178     1,263
                                                              -------   -------   -------
Increase (decrease) in cash and cash equivalents............       78        36       (87)
Cash and cash equivalents
  Beginning of period.......................................       53        17       104
                                                              -------   -------   -------
  End of period.............................................  $   131   $    53   $    17
                                                              =======   =======   =======
</Table>

                            See accompanying notes.

                                        34
<PAGE>

                              EL PASO CGP COMPANY

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

<Table>
<Caption>
                                                                              YEAR ENDED DECEMBER 31,
                                                              -------------------------------------------------------
                                                                    2001                2000               1999
                                                              -----------------   ----------------   ----------------
                                                               SHARES    AMOUNT   SHARES    AMOUNT   SHARES    AMOUNT
                                                              --------   ------   -------   ------   -------   ------
<S>                                                           <C>        <C>      <C>       <C>      <C>       <C>
Preferred stock, par value 33 1/3c per share, authorized
  50,000 shares cumulative convertible preferred
  $1.19, Series A: Beginning balance........................        52   $  --         53   $  --         56   $   --
  Converted to common stock.................................        --      --         (1)     --         (3)      --
  Converted to El Paso common stock.........................       (52)
                                                              --------   ------   -------   ------   -------   ------
        Ending balance......................................        --      --         52      --         53       --
                                                              ========   ======   =======   ======   =======   ======
  $1.83, Series B: Beginning balance........................        51      --         58      --         61       --
  Converted to common stock.................................        --      --         (7)     --         (3)      --
  Converted to El Paso common stock.........................       (51)
                                                              --------   ------   -------   ------   -------   ------
        Ending balance......................................        --      --         51      --         58       --
                                                              ========   ======   =======   ======   =======   ======
  $5.00, Series C: Beginning balance........................        26      --         27      --         28       --
  Converted to common stock.................................        --      --         (1)     --         (1)      --
  Converted to El Paso common stock.........................       (26)
                                                              --------   ------   -------   ------   -------   ------
        Ending balance......................................        --      --         26      --         27       --
                                                              ========   ======   =======   ======   =======   ======
Class A common stock, par value 33 1/3c per share,
  authorized 2,700 shares
  Beginning balance.........................................       311      --        345      --        354       --
  Converted to common stock.................................        --      --        (35)     --        (12)      --
  Conversion of preferred stock and exercise of stock
    options.................................................        --      --          1      --          3       --
  Converted to El Paso common stock.........................      (311)
                                                              --------   ------   -------   ------   -------   ------
        Ending balance......................................        --      --        311      --        345       --
                                                              ========   ======   =======   ======   =======   ======
Common stock, par value 33 1/3c per share, authorized
  500,000 shares
  Beginning balance.........................................   219,605      73    217,705      72    216,765       72
  Exercise of stock options.................................        86      --      1,793       1        863       --
  Conversion to El Paso common stock........................  (219,690)    (73)        --                 --
  Other.....................................................        --      --        107      --         77       --
                                                              --------   ------   -------   ------   -------   ------
        Ending balance......................................         1      --    219,605      73    217,705       72
                                                              ========   ======   =======   ======   =======   ======
Additional paid-in capital
  Beginning balance.........................................             1,044              1,032               1,016
  Merger-related equity exchange............................               (59)                --                  --
  Capital contribution from El Paso.........................               278                 --                  --
  Tax reallocation..........................................                36                 --                  --
  Other.....................................................                 6                 12                  16
                                                                         ------             ------             ------
        Ending balance......................................             1,305              1,044               1,032
                                                                         ======             ======             ======
Retained earnings
  Beginning balance.........................................             3,573              2,973               2,528
  Net income (loss) for period..............................              (188)               654                 499
  Dividends on common stock, 25c per share in 2000 and
    1999....................................................                --                (54)                (54)
                                                                         ------             ------             ------
        Ending balance......................................             3,385              3,573               2,973
                                                                         ======             ======             ======
Accumulated other comprehensive income
  Beginning balance.........................................                (8)                (8)                 (8)
  Other comprehensive income................................               288                 --                  --
                                                                         ------             ------             ------
        Ending balance......................................               280                 (8)                 (8)
                                                                         ======             ======             ======
Treasury stock, at cost
  Beginning balance.........................................    (4,395)   (132)    (4,396)   (132)    (4,396)    (132)
  Retirement of treasury shares.............................     4,395     132         --      --         --       --
  Other.....................................................        --      --          1      --         --       --
                                                              --------   ------   -------   ------   -------   ------
        Ending balance......................................        --      --     (4,395)   (132)    (4,396)    (132)
                                                              ========   ------   =======   ------   =======   ------
        Total...............................................             $4,970             $4,550             $3,937
                                                                         ======             ======             ======
</Table>

                            See accompanying notes.

                                        35
<PAGE>

                              EL PASO CGP COMPANY

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

<Table>
<Caption>
                                                               YEAR ENDED DECEMBER 31,
                                                              -------------------------
COMPREHENSIVE INCOME                                           2001      2000     1999
--------------------                                          -------   ------   ------
<S>                                                           <C>       <C>      <C>
Net income (loss)...........................................   $(188)    $654     $499
                                                               -----     ----     ----
  Foreign currency translation adjustments..................     (30)      --       --
  Unrealized net gains (losses) from cash flow hedging
     activities
     Cumulative-effect transition adjustment (net of tax of
      $248).................................................    (459)      --       --
     Reclassification of initial cumulative-effect of
      transition adjustment at original value (net of tax of
      $246).................................................     456       --       --
     Additional reclassification adjustments for changes in
      initial value to settlement date (net of tax of
      $220).................................................    (406)      --       --
     Unrealized mark-to-market gains arising during period
      (net of tax of $398)..................................     727       --       --
                                                               -----     ----     ----
       Other comprehensive income...........................     288       --       --
                                                               -----     ----     ----
Comprehensive income........................................   $ 100     $654     $499
                                                               =====     ====     ====
</Table>

<Table>
<Caption>
ACCUMULATED OTHER COMPREHENSIVE INCOME
--------------------------------------
<S>                                                           <C>     <C>    <C>
Beginning balances as of January 1, ........................  $  (8)  $ (8)  $ (8)
  Foreign currency translation adjustments..................    (30)    --     --
  Unrealized net gains (losses) from cash flow hedging
     activities
     Cumulative-effect of transition adjustment, net of
      taxes.................................................   (459)    --     --
     Reclassification of initial cumulative-effect
      transition adjustment at original value, net of
      taxes.................................................    456     --     --
     Additional reclassification adjustments for changes in
      initial value to settlement date, net of taxes........   (406)    --     --
     Unrealized mark-to-market gains arising during period,
      net of taxes..........................................    727     --     --
                                                              -----   ----   ----
Balance as of December 31,..................................  $ 280   $ (8)  $ (8)
                                                              =====   ====   ====
</Table>

                            See accompanying notes.

                                        36
<PAGE>

                              EL PASO CGP COMPANY

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

  Basis of Presentation

     Our consolidated financial statements include the accounts of all
majority-owned, controlled subsidiaries after the elimination of all significant
intercompany accounts and transactions. Our financial statements for prior
periods include reclassifications that were made to conform to the current year
presentation. Those reclassifications had no impact on reported net income or
stockholder's equity.

  Principles of Consolidation

     We consolidate entities when we have the ability to control the operating
and financial decisions and policies of that entity. Where we can exert
significant influence over, but do not control, those policies and decisions, we
apply the equity method of accounting. We use the cost method of accounting
where we are unable to exert significant influence over the entity. The
determination of our ability to control or exert significant influence over an
entity involves the use of judgment of the extent of our control or influence
and that of the other equity owners or participants of the entity.

  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.

  Cash and Cash Equivalents

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

  Allowance for Doubtful Accounts

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

  Inventory

     Our inventory consists of refined products, crude oil and chemicals,
materials and supplies, natural gas in storage for non-trading purposes and
coal. We use the first-in, first-out method to account for our refined products,
crude oil and chemicals inventories and the average cost method to account for
our other inventories. We value all inventory at the lower of its cost or market
value.

  Natural Gas and Oil Imbalances

     Natural gas and oil imbalances occur when the actual amount of natural gas
or oil delivered from or received by a pipeline system, processing plant or
storage facility differs from the contractual amount scheduled to be delivered
or received. We value these 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 unconsolidated
affiliates. Imbalances owed to others are reported on

                                        37
<PAGE>

the balance sheet as either trade accounts payable or accounts payable to
unconsolidated 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 the fair value of the assets acquired. We
capitalize direct costs, such as labor and materials, and indirect costs, such
as overhead and interest. We capitalize the major units of property replacements
or improvements and expense minor items.

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

<Table>
<Caption>
                                                                REMAINING
                    TYPE                         METHOD        USEFUL LIVES      RATES
--------------------------------------------  -------------    ------------    ----------
                                                                (IN YEARS)
<S>                                           <C>              <C>             <C>
Pipeline and storage systems................  Straight-line        2-61         2% to 27%
Refining, crude oil and chemical                                   1-33
  facilities................................  Straight-line                     3% to 20%
Power facilities............................  Straight-line        2-14         5% to 33%
Gathering and processing systems............  Straight-line        1-40         3% to 25%
Coal facilities.............................  Straight-line        1-30         3% to 33%
Transportation equipment....................  Straight-line         1-5        10% to 33%
Buildings and improvements..................  Straight-line        1-43         2% to 14%
Office and miscellaneous equipment..........  Straight-line        1-10         5% to 33%
</Table>

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

  Asset Impairments

     We evaluate our long-lived assets for impairment 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, operating costs, legal, regulatory and other factors, and
these assumptions can change either positively or negatively.

  Natural Gas and Oil Properties

     We use the full cost method to account for our natural gas and oil
properties. Under the full cost method, substantially all productive and
nonproductive costs incurred in connection with the acquisition, exploration and
development of natural gas and oil reserves are capitalized. These capitalized
costs include the costs of all unproved properties, internal costs directly
related to acquisition and exploration activities and capitalized interest.

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

                                        38
<PAGE>

     We do not recognize a gain or loss on sales of our natural gas and oil
properties, unless the properties sold are significant. We treat sales as an
adjustment to the cost of our properties.

  Planned Major Maintenance

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

     In our domestic refining business, repair and maintenance costs for planned
major maintenance activities are accrued as a liability in a systematic and
rational manner over the period of time until the planned major maintenance
activities occur. Any difference between the accrued liability and the actual
costs incurred in performing the maintenance activities are charged or credited
to expense at the time the maintenance occurs. At our international refineries,
the cost of each major maintenance activity is capitalized and amortized to
expense in a systematic and rational manner over the estimated period extending
to the next planned major maintenance activity. The types of costs we accrue in
conjunction with major maintenance at our refineries are outside contractor
costs, materials and supplies, company labor and other outside services. For our
domestic operations, we had accruals for major maintenance of $36 million and
$51 million at December 31, 2001 and 2000, and for our international operations,
we capitalized $56 million and $53 million at December 31, 2001 and 2000.

  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 charge in our income statement.

  Revenue Recognition

     Our 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 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.

     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

                                        39
<PAGE>

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 for
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 that involve cash settlements or physical delivery of a
       commodity;

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

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

     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 EITF Issue 98-10, Accounting for Contracts Involved in
Energy Trading and Risk Management Activities. 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 natural gas and oil production,
refining, natural gas transmission and power generation 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 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

                                        40
<PAGE>

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 other valuation techniques
or models to estimate market values. These modeling techniques require us to
make estimations of future prices, price correlation and market volatility and
liquidity. Our 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 tax
directly to the IRS and bills or refunds its subsidiaries for their portion of
these income tax payments. Prior to 2001, we filed a separate tax return and
were not subject to El Paso's tax sharing policy.

  Excise Taxes

     In our retail activities, we account for excise taxes by recording amounts
billed to customers in operating revenues with a corresponding entry for amounts
owed in operating expenses. In our refining and marketing operations, we do not
record the amounts of excise taxes we bill and collect from customers in
revenues. Rather, we record a receivable from our customers and a payable to the
government agencies or suppliers. As of December 31, 2001, 2000 and 1999, we had
recorded approximately $69 million, $198 million and $231 million in excise
taxes related to our retail activities. Additionally in 2001, we recorded $323
million of excise taxes on our balance sheet relating to our refining and
marketing operations.
                                        41
<PAGE>

  Foreign Currency Transactions and Translation

     We record all currency transaction gains and losses in income. The net
currency loss recorded to income was insignificant in 2001 and 2000. The U.S.
dollar is the functional currency for substantially all of our foreign
operations. For those operations, all gains and losses from currency
translations are included in income currently. For foreign operations whose
functional currency is deemed to be other than the U.S. dollar, assets and
liabilities are translated at year-end exchange rates and included as a separate
component of comprehensive income and stockholders' equity. The cumulative
currency translation loss recorded in accumulated other comprehensive income was
$38 million and $8 million at December 31, 2001 and 2000. Revenues and expenses
are translated at average exchange rates prevailing during the year.

  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. MERGER WITH EL PASO CORPORATION

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

     Under a FTC order, as a result of our merger with El Paso, we sold our
Gulfstream pipeline project, our 50 percent interest in the Stingray and U-T
Offshore pipeline systems and our investments in the Empire State and Iroquois
pipeline systems. For the year ended December 31, 2001, net proceeds from these
sales were approximately $184 million, and we recognized an extraordinary net
loss of approximately $11 million, net of income taxes of approximately $5
million.

3. MERGER-RELATED COSTS AND ASSET IMPAIRMENTS

     The following table reflects costs related to our merger with El Paso and
asset impairments for the years ended December 31, 2001 and 2000. We incurred no
merger or asset impairment charges in 1999.

<Table>
<Caption>
                                                              2001     2000
                                                              -----    -----
                                                              (IN MILLIONS)
<S>                                                           <C>      <C>
Merger-related costs........................................  $977      $13
Asset impairments...........................................     9       21
                                                              ----      ---
                                                              $986      $34
                                                              ====      ===
</Table>

                                        42
<PAGE>

     Merger-Related Costs.  Our merger-related costs relate to our merger with
El Paso and consisted of the following for the years ended December 31:

<Table>
<Caption>
                                                              2001     2000
                                                              -----    -----
                                                              (IN MILLIONS)
<S>                                                           <C>      <C>
Employee severance, retention and transition costs..........  $586      $--
Transaction costs...........................................     7       13
Business and operational integration costs..................   122       --
Merger-related asset impairments............................   162       --
Other.......................................................   100       --
                                                              ----      ---
                                                              $977      $13
                                                              ====      ===
</Table>

     Employee severance, retention and transition costs include direct payments
to, and benefit costs for, severed employees and early retirees that occurred as
a result of our merger-related workforce reduction and consolidation. Following
the merger, El Paso completed an employee restructuring across all of our
operating segments, resulting in the reduction of 3,200 full-time positions
through a combination of early retirements and terminations. Employee severance
costs include actual severance payments and costs for pension and
post-retirement benefits settled and curtailed under existing benefit plans as a
result of these restructurings. Retention charges include payments to employees
who were retained following the mergers and payments to employees to satisfy
contractual obligations. Transition costs relate to costs to relocate employees
and costs for severed and retired employees arising after their severance date
to transition their jobs into the ongoing workforce. The pension and
post-retirement benefits were accrued on the merger date and will be paid over
the applicable benefit periods of the terminated and retired employees. All
other costs were expensed as incurred and have been paid.

     Also included in the 2001 employee severance, retention and transition
costs, was a charge of $278 million resulting from the issuance of approximately
4 million shares of El Paso common stock on the merger date in exchange for the
fair value of our employees' and directors' stock options.

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

     Business and operational integration costs include charges to consolidate
facilities and operations of our business segments, such as lease termination
and abandonment charges, recognition of the mark-to-market value of energy
trading contracts resulting from changes in how these contracts are managed
under the El Paso combined operating strategy and incremental fees under
software and seismic license agreements. Also included in the 2001 charges are
approximately $121 million in estimated lease related costs to relocate our
pipeline operations from Detroit, Michigan to Houston, Texas. These charges were
accrued at the time we completed our relocations and closed this office. The
amounts accrued will be paid over the term of the applicable non-cancelable
lease agreements. All other costs were expensed as incurred.

     Merger-related asset impairments relate to write-offs or write-downs of
capitalized costs for duplicate systems, redundant facilities and assets whose
value was impaired as a result of decisions on the strategic direction of our
combined operations following the merger. These charges occurred in our Merchant
Energy, Production and Pipelines segments, and all of these assets have either
had their operations suspended or continue to be held for use. The charges taken
were based on a comparison of the cost of the assets to their estimated fair
value to the ongoing operations based on this change in operating strategy.

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

     Asset Impairments.  The 2001 asset impairment charges resulted from the
inability to recover capitalized costs of Merchant Energy's Corpus Christi
refinery and related assets as a result of the lease of these assets to Valero
in June 2001. The 2000 charges consisted of the impairment of coal mining and
refining

                                        43
<PAGE>

assets. These impairments 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 operation has been suspended.

4. CHANGES IN ACCOUNTING ESTIMATES

     Included in our operation and maintenance costs for the year ended December
31, 2001, were approximately $317 million in costs related to changes in
accounting estimates which consist of $232 million in additional environmental
remediation liabilities, $47 million of additional accrued legal obligations and
a $38 million charge to reduce the value of our spare parts inventories to
reflect changes in the usability of these parts in our worldwide operations.
These changes were primarily the result of several events that occurred as part
of and following our merger with El Paso, including the consolidation of
numerous operating locations, the sale of a majority of our retail gas stations,
the shutdown of our Midwest refining operations and the lease of our Corpus
Christi refinery. These changes were also a direct result of a fire at our Aruba
refinery. Also impacting these amounts was the evaluation of the operating
standards, strategies and plans of our combined company following the merger.
These charges are included as operating expenses in our income statement and
reduced our net income before extraordinary items and net income for the year
ended December 31, 2001, by approximately $241 million.

5. CEILING TEST CHARGES

     Under the full cost method of accounting for natural gas and oil
properties, we perform quarterly ceiling tests to evaluate whether the carrying
value of natural gas and oil properties exceeds the present value of future net
revenues, discounted at 10 percent, plus the lower of cost or fair market value
of unproved properties. During the third quarter of 2001, capitalized costs
exceeded this ceiling limit by $115 million, including $87 million for our
Canadian full cost pool and $28 million for our Brazilian full cost pool. These
charges were based on the November 1, 2001 daily posted oil and natural gas
sales prices, adjusted for oilfield or gas gathering hub and wellhead price
differences as appropriate. This non-cash write-down is included in our income
statement as ceiling test charges.

     We use financial instruments to hedge against volatility of natural gas and
oil prices. The impact of these hedges was considered in the determination of
our ceiling test charge during 2001 and will be factored into future ceiling
test calculations. Had the impact of our hedges not been included in calculating
our 2001 ceiling test charge, the charge would not have materially changed since
we do not significantly hedge our international production activities.

     Also as mentioned above, our 2001 charge was computed based on daily posted
prices on November 1, 2001. Had we computed this charge based on the daily oil
and natural gas prices as of September 30, 2001, the charge would have been
approximately $255 million, including approximately $227 million for our
Canadian full cost pool and $28 million for our Brazilian full cost pool,
including the impact on future cash flows of our hedging program. Had the impact
of our hedging program been excluded, the charges would have been approximately
the same for our international full cost pools and production operations, but we
would have incurred an additional charge of approximately $830 million related
to our U.S. full cost pool.

6. INCOME TAXES

     Pretax income (loss) before extraordinary items is composed of the
following for the years ended December 31:

<Table>
<Caption>
                                                              2001    2000   1999
                                                              -----   ----   ----
                                                                 (IN MILLIONS)
<S>                                                           <C>     <C>    <C>
United States...............................................  $(137)  $721   $554
Foreign.....................................................     38    185    119
                                                              -----   ----   ----
                                                              $ (99)  $906   $673
                                                              =====   ====   ====
</Table>

                                        44
<PAGE>

     The following table reflects the components of income tax expense included
in income (loss) before extraordinary items for the years ended December 31:

<Table>
<Caption>
                                                              2001   2000   1999
                                                              ----   ----   ----
                                                                (IN MILLIONS)
<S>                                                           <C>    <C>    <C>
Current
  Federal...................................................  $ 94   $ 41   $ 45
  State.....................................................    (5)    (1)     9
  Foreign...................................................     6      9      8
                                                              ----   ----   ----
                                                                95     49     62
                                                              ----   ----   ----
Deferred
  Federal...................................................    35    189    112
  State.....................................................   (15)    11     (3)
  Foreign...................................................   (37)     3      3
                                                              ----   ----   ----
                                                               (17)   203    112
                                                              ----   ----   ----
          Total income tax expense..........................  $ 78   $252   $174
                                                              ====   ====   ====
</Table>

     Our tax expense, included in income (loss) before extraordinary items,
differs from the amount computed by applying the statutory federal income tax
rate of 35 percent for the following reasons for the years ended December 31:

<Table>
<Caption>
                                                              2001    2000    1999
                                                              ----    ----    ----
                                                                 (IN MILLIONS)
<S>                                                           <C>     <C>     <C>
Tax expense at the statutory federal rate of 35%............  $(35)   $317    $236
Increase (decrease)
  Tight sands gas credit....................................    --      (6)     (6)
  State income taxes........................................   (13)      6       4
  Foreign income taxed at different tax rates...............    (2)    (48)    (52)
  Depreciation, depletion and amortization..................    20     (17)    (10)
  Non-deductible portion of merger costs and other tax
     adjustments to provide for revised estimated
     liabilities............................................   106      --      --
  Non-deductible dividends on preferred stock of
     subsidiaries...........................................     3       4      --
  Other.....................................................    (1)     (4)      2
                                                              ----    ----    ----
Income tax expense..........................................  $ 78    $252    $174
                                                              ====    ====    ====
Effective tax rate..........................................   (79)%    28%     26%
                                                              ====    ====    ====
</Table>

                                        45
<PAGE>

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

<Table>
<Caption>
                                                               2001     2000
                                                              ------   ------
                                                               (IN MILLIONS)
<S>                                                           <C>      <C>
Deferred tax liabilities
  Property, plant and equipment.............................  $1,771   $1,780
  Pensions and benefit costs................................      --      160
  Investments in unconsolidated affiliates..................     255      191
  Price risk management activities..........................     173       --
  Other assets..............................................     507      114
                                                              ------   ------
          Total deferred tax liability......................   2,706    2,245
                                                              ------   ------
Deferred tax assets
  U.S. net operating loss and tax credit carryovers.........     256      212
  Environmental liability...................................      99       --
  Employee benefit and deferred compensation obligations....      12       --
  Other liabilities.........................................     564      169
                                                              ------   ------
          Total deferred tax asset..........................     931      381
                                                              ------   ------
Net deferred tax liability..................................  $1,775   $1,864
                                                              ======   ======
</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 $754 million. Since these
earnings have been or are intended to be indefinitely reinvested in foreign
operations, no provision has been made for any U.S. taxes or foreign withholding
taxes that may be applicable upon actual or deemed repatriation. If a
distribution of these earnings were to be made, we might be subject to both
foreign withholding taxes and U.S. income taxes, net of any allowable foreign
tax credits or deductions. However, an estimate of these taxes is not
practicable. For these same reasons, we have not recorded a provision for U.S.
income taxes on the foreign currency translation adjustment recorded in other
comprehensive income.

     The tax benefit associated with the exercise of non-qualified stock options
and the vesting of restricted stock, as well as restricted stock dividends,
reduced taxes payable by $5 million in 2001 (allocated to us under El Paso's tax
sharing policy), $18 million in 2000 and $6 million in 1999. These benefits are
included in additional paid-in capital in our balance sheets.

     As of December 31, 2001, we had alternative minimum tax credits of $153
million that carryover indefinitely and $293 million of net operating loss
carryovers for which the carryover period ends in 2021. 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 IRS regulations.

                                        46
<PAGE>

7. 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:
     Long-term debt and other obligations, including
       current maturities.............................  $ 6,417     $ 6,404     $ 6,293     $ 6,413
     Notes payable to unconsolidated affiliates.......       67          67          --          --
     Company obligated preferred securities of
       subsidiaries...................................      300         299         300         293
     Trading instruments
       Futures contracts..............................      (34)        (34)         15          15
       Option contracts...............................       (4)         (4)         12          12
       Swap and forward contracts(1)..................       (4)         (4)        226         226
Other financial instruments:
     Non-Trading instruments(2)
       Commodity swap and forward contracts...........  $   491     $   491     $    --     $  (692)
       Commodity futures contracts....................       10          10          --          --
</Table>

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

(1) Excludes all physical contracts.
(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.

                                        47
<PAGE>

  Commodity Trading Activities

     Prior to October 2000, we conducted our natural gas and power marketing and
trading activities through Engage Energy U.S., L.P. and Engage Canada, L.P., a
joint venture between us and Westcoast Energy Inc., a major Canadian natural gas
company. During the fourth quarter of 2000, we terminated the Engage joint
venture and assumed Engage's U.S. trading activities. In February 2001, we
transferred these activities to a subsidiary of El Paso. See Note 17 for a
further discussion of this transfer.

     We recognized gross margins from our trading activities of $15 million and
$33 million for the years 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. The information below includes information for the trading
operations we assumed from Engage for the periods it was consolidated in our
operations.

<Table>
<Caption>
                                                                              AVERAGE FAIR
                                                                              VALUE FOR THE
                                                                               YEAR ENDED
                                                    ASSETS    LIABILITIES    DECEMBER 31,(1)
                                                    ------    -----------    ---------------
                                                                 (IN MILLIONS)
<S>                                                 <C>       <C>            <C>
2001
Futures contracts.................................  $  150      $  (184)         $  (13)
Option contracts..................................      10          (14)            (15)
Swap and forward contracts........................      25          (10)             --
2000
Futures contracts.................................  $   15      $    --          $   (3)
Option contracts..................................      59          (47)              9
Swap and forward contracts........................     644         (612)            170
</Table>

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

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

  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:
  Crude oil (MMBbls)...............................       104            57             3
2000
Energy Commodities:
  Natural gas (Bcf)................................       767           677             9
  Crude oil (MMBbls)...............................        42            39             2
</Table>

     The notional amounts included in the table above reflect the contracted
notional volume 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 weighted average maturity of our entire portfolio of price risk
management activities was approximately three 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 transactions
subject to parameters established by our risk management committee. We monitor
market risks

                                        48
<PAGE>

through a risk control committee operating independently from the units that
create or actively manage these risk exposures to ensure compliance with our
stated risk management policies.

     We measure and adjust the risk in 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)    TOTAL
                                              -------------------    -------------------    ------
                                                                 (IN MILLIONS)
<S>                                           <C>                    <C>                    <C>
Energy marketers............................         $ 18                   $ --             $ 18
Financial institutions......................          167                     --              167
                                                     ----                   ----             ----
          Total assets from trading price
            risk management activities......         $185                   $ --             $185
                                                     ====                   ====             ====
</Table>

<Table>
<Caption>
                                             ASSETS FROM TRADING PRICE RISK MANAGEMENT ACTIVITIES
                                                           AS OF DECEMBER 31, 2000
                                            ------------------------------------------------------
                                                                           BELOW
                                            INVESTMENT GRADE(1)     INVESTMENT GRADE(1)     TOTAL
                                            --------------------    --------------------    ------
                                                                (IN MILLIONS)
<S>                                         <C>                     <C>                     <C>
Energy marketers..........................          $151                    $26              $177
Financial institutions....................           372                     --               372
Natural gas and oil producers.............            29                      1                30
Natural gas and electric utilities........            62                     14                76
Industrials...............................             5                     --                 5
Natural gas and electric utilities not
  publicly traded.........................            58                     --                58
                                                    ----                    ---              ----
          Total assets from trading price
            risk management activities....          $677                    $41              $718
                                                    ====                    ===              ====
</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 credit ratings that do not meet the criteria of
   "Investment Grade".

     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.

                                        49
<PAGE>

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

<Table>
<Caption>
                                                   2001                              2000
                                      -------------------------------   -------------------------------
                                      NOTIONAL VOLUME                   NOTIONAL VOLUME
                                      ---------------      MAXIMUM      ---------------      MAXIMUM
                                       BUY      SELL    TERM IN YEARS    BUY      SELL    TERM IN YEARS
                                      ------   ------   -------------   ------   ------   -------------
<S>                                   <C>      <C>      <C>             <C>      <C>      <C>
Commodity
  Natural Gas (TBtu)................      12       12         6              1      157         2
  Crude oil and refined products
     (MMBbls).......................     117      113         1            115      135         1
</Table>

     As of December 31, 2001, we had an interest rate swap transaction with a
notional amount of $240 million exchanging LIBOR, a variable interest rate, for
a fixed rate of 3.07%. This swap was entered into as a hedge of the variable
interest rates on a loan with a principal amount of $240 million that matures in
March 2004. The swap converts the variable interest payments on the loan to a
fixed rate of 4.49% until the swap terminates in June 2003. The fair value of
this swap was immaterial as of December 31, 2001.

     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.

8. ACCOUNTING FOR HEDGING ACTIVITIES

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

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

     Cash Flow Hedges.  A majority of our commodity sales and purchases are at
spot market or forward market prices. We use futures, forward contracts and
swaps to limit our exposure to fluctuations in the commodity markets and allow
for a fixed cash flow stream from these activities. As of December 31, 2001, the
value of cash flows hedges included in accumulated other comprehensive income
was an unrealized gain of $318 million, net of income taxes. We estimate that
unrealized gains of $165 million, net of income taxes, will be reclassified from
accumulated other comprehensive income over the next 12 months.
Reclassifications occur upon physical delivery of the hedge commodity and the
corresponding expiration of the hedge. The maximum term of our cash flow hedges
is 2 years; however, most of our cash flow hedges expire within the next 12
months.

     Our accumulated other comprehensive income also includes our proportionate
share of amounts recorded in other comprehensive income by our unconsolidated
affiliates who use derivatives as cash flow hedges, which was less than $1
million at December 31, 2001.

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

                                        50
<PAGE>

9. INVENTORY

     Our inventory consisted of the following at December 31:

<Table>
<Caption>
                                                              2001     2000
                                                              ----    ------
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
Refined products, crude oil and chemicals...................  $576    $1,004
Coal, materials and supplies and other......................   117       163
                                                              ----    ------
          Total.............................................  $693    $1,167
                                                              ====    ======
</Table>

10. PROPERTY, PLANT AND EQUIPMENT

     At December 31, 2001 and 2000, we had approximately $1,030 million and
$1,481 million construction work in progress included in our property, plant and
equipment.

     In June 2001, we entered into a 20-year lease agreement related to our
Corpus Christi refinery and related assets with Valero Energy Corporation. Under
the lease, Valero pays us a quarterly amount that increases after the second
year of the lease. For the year ended December 31, 2001, we recorded $11 million
in lease income related to this lease. In addition, Valero has the option to
purchase the plant and related assets in 2003 for approximately $294 million,
and a similar option each year thereafter at an annually increasing amount. The
net book value of the plant and related assets was approximately $225 million at
December 31, 2001. Based on the terms, the lease qualified as an operating lease
with total minimum lease payments of $811 million with future minimum lease
payments totaling $797 million; $19 million in 2002; $37 million in 2003; $43
million in each of 2004, 2005 and 2006; and a total of $612 million thereafter.

11. DEBT, OTHER FINANCING OBLIGATIONS AND OTHER CREDIT FACILITIES

     At December 31, 2001, our weighted average interest rate on our commercial
paper and short-term credit facilities was 2.4%, and at December 31, 2000, it
was 7.15%. We had the following short-term borrowings and other financing
obligations at December 31:

<Table>
<Caption>
                                                               2001     2000
                                                              ------   ------
                                                               (IN MILLIONS)
<S>                                                           <C>      <C>
Commercial paper............................................  $   --   $  455
Short-term credit facilities................................      30      340
Notes payable to unconsolidated affiliates..................      67       --
Current maturities of long-term debt and other financing
  obligations...............................................   1,310      296
Other.......................................................       3        3
                                                              ------   ------
                                                              $1,410   $1,094
                                                              ======   ======
</Table>

  Credit Facilities

     In January 2001, we terminated approximately $1.5 billion in revolving
credit facilities and became a designated borrower under El Paso's 364-day and
3-year revolving credit and competitive advance facilities. In June 2001, El
Paso replaced its existing 364-day revolving credit facility, and we are not a
designated borrower under the new facility. The interest rate on the 3-year
revolving credit and competitive advance facility varies and was based on the
LIBOR plus 50 basis points at December 31, 2001. No amounts were outstanding
under this facility as of December 31, 2001.

                                        51
<PAGE>

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

<Table>
<Caption>
                                                               2001     2000
                                                              ------   ------
                                                               (IN MILLIONS)
<S>                                                           <C>      <C>
Long-term debt
  El Paso CGP
     Notes payable (revolving credit agreement).............  $   --   $  135
     Senior notes, 6.2% through 10.375%, due 2001 through
      2010..................................................   1,565    1,650
     Floating rate senior notes, due 2002 and 2003(1).......     600      600
     Senior debentures, 6.375% through 10.75%, due 2003
      through 2037..........................................   1,497    1,497
     FELINE PRIDES, 6.625% due 2004.........................     460      460
     Valero lease financing loan due 2004...................     240       --
  El Paso Production Company
     Floating rate notes, due 2005 and 2006.................     200      100
  ANR Pipeline
     Debentures, 7.0% through 9.625%, due 2021 through
      2025..................................................     500      500
  Colorado Interstate Gas
     Debentures, 6.85% and 10.0%, due 2005 and 2037.........     280      280
  Other.....................................................     369      233
                                                              ------   ------
                                                               5,711    5,455
  Less:
     Unamortized discount...................................       9       12
     Current maturities.....................................     720      147
                                                              ------   ------
       Long-term debt, less current maturities..............   4,982    5,296
                                                              ------   ------
Other Financing Obligations
  Crude oil prepayments.....................................     500      500
  Natural gas production payment............................     215      350
                                                              ------   ------
                                                                 715      850
  Less:
     Current maturities.....................................     590      149
                                                              ------   ------
       Other financing obligations, less current
        maturities..........................................     125      701
                                                              ------   ------
          Total long-term debt and other financing
            obligations, less current maturities............  $5,107   $5,997
                                                              ======   ======
</Table>

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

(1) In March 2002, we retired $400 million of these notes.

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

<Table>
<S>                                                           <C>
2002........................................................  $1,310
2003........................................................     380
2004........................................................     996
2005........................................................     310
2006........................................................     763
Thereafter..................................................   2,667
                                                              ------
     Total long-term debt and other financing obligations
       including current maturities.........................  $6,426
                                                              ======
</Table>

     In October 2001, we borrowed $240 million due in 2004 under a loan
agreement. The loan is collateralized by the lease payments from Valero under
their lease of our Corpus Christi refinery.

     In 1999, we issued a total of 18,400,000 FELINE PRIDES(SM) consisting of
17,000,000 Income PRIDES with a stated value of $25 and 1,400,000 Growth PRIDES
with a stated value of $25. The Income PRIDES

                                        52
<PAGE>

consist of a unit comprised of a Senior Debenture and a purchase contract under
which the holder is obligated to purchase from us by no later than August 16,
2002 for $25 (the stated price) a number of shares of our common stock. The
Growth PRIDES consist of a unit comprised of a purchase contract under which the
holder is obligated to purchase from us by no later than August 16, 2002 for $25
(the stated price) a number of shares of our common stock and a 2.5% undivided
beneficial interest in a three-year Treasury security having a principal amount
at maturity equal to $1,000. Under the terms of the purchase contract in effect
prior to the merger with El Paso, the number of shares of common stock the
holder of a PRIDE received varied between 0.5384 and 0.6568 shares, depending on
the price of our common stock.

     As a result of the merger with El Paso, and under the terms of the purchase
contract, the number of shares the holder of a PRIDE is entitled and required to
receive upon settlement became fixed at 0.6622 shares of El Paso common stock.
This will result in the issuance of approximately 12.2 million shares of El Paso
common stock.

     Our other financing obligations consist of crude oil prepayments received
from third parties in exchange for our agreement to deliver a fixed quantity of
crude oil to a specified delivery point in the future and a production payment
received in exchange for delivery of a fixed quantity of natural gas from our
future production. These agreements, by their terms, can only be settled through
the delivery of the commodity. We have entered into commodity swaps to
effectively lock-in the value of these commitments to the third party upon
delivery of the commodity. We will continue to deliver natural gas under the
production payment agreement according to its terms, but consider these
agreements to be financing arrangements. The carrying cost of the prepayments
and the production payment are recognized as interest expense in our income
statement.

  Other Financing Arrangements

     During 2000, El Paso formed a series of companies to provide financing to
invest in various El Paso capital projects and other assets. The proceeds are
collateralized by various fixed assets, including our Colorado Interstate Gas
transmission system.

  Other Financial Activities

     Our significant long-term debt borrowing and repayment activities during
2001 were as follows:
<Table>
<Caption>
                                                                                                                  NET
        DATE                    COMPANY                       TYPE                INTEREST RATE   PRINCIPAL   PROCEEDS(1)
        ----                    -------                       ----                -------------   ---------   -----------
                                                                                                       (IN MILLIONS)
<S>                      <C>                     <C>                              <C>             <C>         <C>
Issuances
2001
  January                El Paso CGP             Crude oil prepayment               Variable       $  150        $150
  October                El Paso CGP             Loan(2)                              4.49%           240         240
  Jan.-Dec.              El Paso Production      Various                             Various          100         100

Retirements
2001
  January                El Paso Production      Crude oil prepayment               Variable       $  150
  February               El Paso CGP             Long-term debt                     Variable          135
  February               El Paso CGP             Long-term debt                      10.00%            85
  Jan.-Dec.              El Paso Production      Natural gas production payment   LIBOR+0.372%        135
  Jan.-Dec.              El Paso CGP             Various                             Various          103

<Caption>

        DATE           DUE DATE
        ----           --------

<S>                    <C>
Issuances
2001
  January                2002
  October                2004
  Jan.-Dec.            2005-2006
Retirements
2001
  January                2001
  February               2001
  February               2001
  Jan.-Dec.              2001
  Jan.-Dec.              2001
</Table>

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

(1) Net proceeds were primarily used to repay short-term borrowings and for
    general corporate purposes.

(2) The loan is collateralized by the lease payments from Valero for our Corpus
    Christi refinery and related assets. The interest rate on the loan is LIBOR
    plus 1.425%. To reduce our exposure to interest rate risk, we entered into a
    swap transaction with a notional amount of $240 million exchanging LIBOR for
    a fixed rate of 3.07%. This transaction results in the payment of a fixed
    rate of 4.495% until the swap terminates in June 2003.

                                        53
<PAGE>

12. SECURITIES OF SUBSIDIARIES AND MINORITY INTERESTS

  Company-obligated Preferred Securities of a Consolidated Trust.

     Coastal Finance I.  In May 1998, we completed a public offering of 12
million mandatory redemption preferred securities on Coastal Finance I, a
business trust, for $300 million. Coastal Finance I holds debt securities of
ours purchased with the proceeds of the preferred securities offering.
Cumulative quarterly distributions are being paid on the preferred securities at
an annual rate of 8.375% of the liquidation amount of $25 per preferred
security. The preferred securities are mandatorily redeemable on the maturity
date, May 13, 2038, and may be redeemed at our option on or after May 13, 2003,
or earlier if various events occur. The redemption price to be paid is $25 per
preferred security, plus accrued and unpaid distributions to the date of
redemption.

  Minority Interests

     Coastal Securities Company Preferred Stock.  In 1996, Coastal Securities
Company Limited, our wholly owned subsidiary, issued 4 million shares of
preferred stock for $100 million. Quarterly cash dividends are being paid on the
preferred stock at a rate based on LIBOR. The preferred shareholders are also
entitled to participating dividends based on various refining margins. Coastal
Securities may redeem the preferred stock for cash at the liquidation price plus
accrued and unpaid dividends.

     Coastal Oil & Gas Resources Preferred Stock.  In 1999, Coastal Oil & Gas
Resources, Inc., our wholly owned subsidiary, issued 50,000 shares of preferred
stock for $50 million. The preferred shareholders are entitled to quarterly cash
dividends at a rate based on LIBOR. The dividend rate is subject to
renegotiation in 2004 and on each fifth anniversary thereafter. In the event
Coastal Oil & Gas Resources and the preferred shareholders are unable to agree
to a new rate, Coastal Oil & Gas Resources must redeem the shares at $1,000 per
share plus any accrued and unpaid dividends, or cause the preferred stock to be
registered with the Securities and Exchange Commission and remarketed. Coastal
Oil & Gas Resources also has the option to redeem all shares on any dividend
rate reset date for $1,000 per share plus any accrued and unpaid preferred
dividends.

     Coastal Limited Ventures Preferred Stock.  In 1999, Coastal Limited
Ventures, Inc., our wholly owned subsidiary, issued 150,000 shares of preferred
stock for $15 million. The preferred shareholders are entitled to quarterly cash
dividends at an annual rate of 6%. The dividend rate is subject to renegotiation
in 2004 and on each fifth anniversary thereafter. In the event Coastal Limited
and the preferred shareholders are unable to agree to a new rate, the preferred
shareholders may call for redemption of all of the preferred shares. The
redemption price is $100 per share plus any accrued and unpaid preferred
dividends thereon. Coastal Limited also has the option to redeem all shares on
any rate reset date for $100 per share plus any accrued and unpaid preferred
dividends.

     Consolidated Partnership.  In December 1999, Coastal Limited contributed
assets to a limited partnership in exchange for a controlling general
partnership interest. Limited interests in the partnership were issued to
unaffiliated investors for $285 million. The limited partners are entitled to a
cumulative priority return based on LIBOR. The return is subject to
renegotiation in 2004 and on each fifth anniversary thereafter. The partnership
has a maximum life of 20 years, but may be terminated sooner subject to certain
conditions, including failure to agree to a new rate. Coastal Limited may
terminate the partnership at any time by repayment of the limited partners'
outstanding capital plus any unpaid priority returns.

13. COMMITMENTS AND CONTINGENCIES

  Legal Proceedings

     In May 1999, one of our subsidiaries was named as a defendant in a suit
filed in the 319th Judicial District Court, Nueces County, Texas by an
individual employed by one of our contractors (Rolando Lopez and Rosanna Barton
v. Coastal Refining & Marketing, Inc. and The Coastal Corporation). The suit
sought damages for injuries sustained at the time of an explosion at one of our
refining plants, and was settled in August 2000 for a total payment of $7
million, of which $5 million was covered by insurance. Three of the

                                        54
<PAGE>

refinery employees intervened in the suit and sought damages for injuries
sustained in the explosion. Those claims were tried in August 2000, resulting in
a $122 million verdict, for which there is insurance coverage. The case has been
appealed to the Thirteenth Court of Appeals of Texas, and all appellate briefing
in that court has been completed. Even if the verdict is upheld on appeal, it
will not have a material adverse effect on our financial position, operating
results or cash flows.

     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 Kansas State Court for further proceedings. A motion
to dismiss this case is pending.

     In October 1992, several property owners in McAllen, Texas, filed suit in
the 93rd Judicial District Court, Hidalgo County, Texas, against, among others,
one of our subsidiaries (Timely Adventures, Inc., et al, v. Phillips Properties,
Inc., et al and Garza v. Coastal Mart, Inc.). The suit sought damages for the
alleged diminution of property value and damages related to the exposure to
hazardous chemicals arising from the operation of service stations and storage
facilities. In July 2000, the trial court entered a judgment for approximately
$1.2 million in actual damages for property diminution and approximately $100
million in punitive damages. The judgment was appealed. An agreement in
principle to settle this case has been reached, and we expect the settlement to
be concluded in March 2002. We have established accruals that we believe are
sufficient to provide for the settlement. The settlement will not have a
material adverse effect on our financial position, operating results or cash
flows.

     In compliance with the 1990 amendments to the Clean Air Act (CAA), we use
the gasoline additive, methyl tertiary-butyl ether (MTBE), in some of our
gasoline. We also produce, buy, sell and distribute MTBE. A number of lawsuits
have been filed throughout the U.S. regarding MTBE's potential impact on water
supplies. We are currently one of several defendants in five such lawsuits in
New York. Our costs and legal exposure related to these lawsuits and claims are
not currently determinable.

     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 $81 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 $260 million
for expected remediation costs. In

                                        55
<PAGE>

addition, we expect to make capital expenditures for environmental matters of
approximately $199 million in the aggregate for the years 2002 through 2006.
These expenditures primarily relate to compliance with clean air regulations.
Our accrued amounts as of December 31, 2001 include a change in our estimated
environmental remediation liabilities as a result of several events that
occurred during 2001 and an evaluation of our operations following the El Paso
merger. See a discussion of this change in estimate in Note 4.

     From May 1999 to March 2001, our Eagle Point Oil Company received several
Administrative Orders and Notices of Civil Administrative Penalty Assessment
from the New Jersey Department of Environmental Protection. All of the
assessments are related to alleged noncompliance with the New Jersey Air
Pollution Control Act pertaining to excess emissions from the first quarter 1998
through the fourth quarter 2000 reported by our Eagle Point refinery in
Westville, New Jersey. The New Jersey Department of Environmental Protection has
assessed penalties totaling approximately $1.1 million for these alleged
violations. Our Eagle Point refinery has been granted an administrative hearing
on issues raised by the assessments and, concurrently, is in negotiations to
settle these assessments.

     In February 2002, we received a Notice of Violation from the EPA alleging
noncompliance with the EPA's fuel regulations from 1996 to 1998. The notice
proposes a penalty of $165,000 for these alleged violations. We are
investigating the allegations and are preparing a response.

     We have been designated, 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 16 active sites under
the Comprehensive Environmental Response, Compensation and Liability Act
(CERCLA) or state equivalents. We have sought to resolve our liability as a PRP
at these 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 approximately $5 million and $8 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 of 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 March 2001, CIG filed a rate case with the FERC proposing increased
rates of $9 million annually and new and enhanced services for its customers.
This filing was required under the settlement of its 1996 general rate case. CIG
received an order from FERC in late April 2001, which suspended the rates until
October 1, 2001, subject to refund, and subject to the outcome of an evidentiary
hearing. On September 26, 2001, the FERC issued an order rejecting two firm
services CIG had proposed in its rate filing and required it to reallocate the
costs allocated to those two services to existing services. CIG has complied
with this order and has arranged with the affected customers to provide service
under existing rate schedules. The evidentiary hearing was suspended pending
ongoing attempts to settle the case.

                                        56
<PAGE>

     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. While we
cannot predict the outcome of the NOPR, 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

     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 two power plants in Pakistan, with a total investment,
including financial guarantees on these projects, of approximately $222 million.
While we are aware of no specific threats or actions against these power plants,
events in that region, including possible retaliation for American military
actions, could impact these projects 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.

  Capital Commitments and Purchase Obligations

     At December 31, 2001, we had capital and investment commitments of $265
million primarily relating to our production, 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 totaling $269 million at December 31, 2001. Our annual
obligations under these agreements are $24 million for the years 2002, 2003,
2004, 2005 and 2006, and $149 million in total thereafter.

  Operating Leases

     We maintain operating leases in the ordinary course of our business
activities. These leases include those for office space and operating facilities
and office and operating equipment, and the terms of the agreements vary from
2002 until 2031. As of December 31, 2001, our total commitments under operating
leases were approximately $255 million.

     Under several of our leases, we have provided residual value guarantees to
the lessor. Under these guarantees, we can either choose to purchase the asset
at the end of the lease term for a specified amount, which is typically equal to
the outstanding loan amounts owed by the lessor, or we can choose to assist in
the sale of the leased asset to a third party. Should the asset not be sold for
a price that equals or exceeds the amount of the guarantee, we would be
obligated for the shortfall. The level of our residual value guarantees are 89.9
percent of the original cost of the leased assets. The total outstanding
residual value guarantees on our operating leases at December 31, 2001, were
$425 million.

                                        57
<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.....................................................        $ 57
   2003.....................................................          47
   2004.....................................................          30
   2005.....................................................          18
   2006.....................................................          12
   Thereafter...............................................          91
                                                                    ----
          Total.............................................        $255
                                                                    ====
</Table>

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

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

     Rental expenses for the years ended December 31, 2001, 2000 and 1999 was
$92 million, $140 million and $120 million.

  Letters of Credit

     We enter into letters of credit in the ordinary course of our operating
activities. As of December 31, 2001, we had outstanding letters of credit of
$166 million related to our marketing and trading activities, our domestic power
development and other operating activities.

  Guarantees

     Our involvement in joint ventures and project level construction and
finance results in the issuance of financial and non-financial guarantees in our
business activities. We also guarantee performance and contractual commitments
of companies within our consolidated group. There are various events and
circumstances that may require us to perform under our guarantees, including:

     - non-payment by the guaranteed party;

     - non-compliance with the covenants of the transactions by the guaranteed
       party;

     - non-compliance by us with the provision of guarantees; and

     - cross-acceleration with other transactions.

     As of December 31, 2001, we had approximately $8 million of guarantees in
connection with our international development and operating activities not
consolidated on our balance sheet and approximately $162 million of guarantees
in connection with our domestic development and operating activities not
consolidated on our balance sheet.

14. RETIREMENT BENEFITS

  Pension and Retirement Benefits

     El Paso maintains a pension plan to provide benefits as determined by a
cash balance formula covering substantially all of its U.S. employees, including
our employees except for employees of our coal and retail operations who are
covered under a separate plan. Also, El Paso maintains a defined contribution
plan covering its U.S. employees, including our employees. El Paso matches 75
percent of participant basic contributions of up to 6 percent, with the matching
contribution being made to the plan's stock fund. Participants can elect to move
the matching contribution at any time into any of the seven remaining funds or
leave them in the stock fund. El Paso is responsible for benefits accrued under
its plan and allocates the related costs to its affiliates.

                                        58
<PAGE>

     Prior to the merger, we maintained both defined benefit and defined
contribution plans. Our pension plan covered substantially all of our U.S.
employees. On April 1, 2001, this primary plan was merged into El Paso's
existing plan. Our employees who were participants in our primary plan on March
31, 2001 receive the greater of cash balance benefits or our plan benefits
accrued through March 31, 2006. In addition, we maintained a defined
contribution plan. Under this plan, we matched 100 percent of basic
contributions of up to 8 percent with matching contributions made in our common
stock. Amounts expensed under this plan were $21 million and $20 million for the
years ended December 31, 2000 and 1999.

  Other Postretirement Benefits

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

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

     The following table sets forth the change in benefit obligation, change in
plan assets, reconciliation of funded status and components of net periodic
benefit cost for pension benefits and other postretirement benefits. Our
benefits are presented and computed as of and for the twelve months ended
December 31, 2000 and September 30, 2001.

<Table>
<Caption>
                                                                            POSTRETIREMENT
                                                       PENSION BENEFITS        BENEFITS
                                                       -----------------    ---------------
                                                        2001      2000       2001     2000
                                                       -------   -------    ------   ------
                                                                  (IN MILLIONS)
<S>                                                    <C>       <C>        <C>      <C>
Change in benefit obligation
  Benefit obligation at beginning of period..........  $  822    $  777      $114     $108
  Service cost.......................................       5        21         1        3
  Interest cost......................................      20        59         9        8
  Participant contributions..........................      --        --         3        2
  Plan amendment.....................................      --        --       (12)      --
  Curtailment and special termination benefit........     137        --        16       --
  Actuarial loss or (gain)...........................      75        10       (15)       3
  Benefits paid......................................     (13)      (45)       (7)     (10)
  Transfer of plan obligations.......................    (962)       --        --       --
                                                       ------    ------      ----     ----
  Benefit obligation at end of period................  $   84    $  822      $109     $114
                                                       ======    ======      ====     ====
</Table>

                                        59
<PAGE>

<Table>
<Caption>
                                                                            POSTRETIREMENT
                                                       PENSION BENEFITS        BENEFITS
                                                       -----------------    ---------------
                                                        2001      2000       2001     2000
                                                       -------   -------    ------   ------
                                                                  (IN MILLIONS)
<S>                                                    <C>       <C>        <C>      <C>
Change in plan assets
  Fair value of plan assets at beginning of period...  $1,971    $1,662      $ 35     $ 29
  Actual return on plan assets.......................    (182)      354         1        1
  Employer contributions.............................      --        --         8       11
  Participant contributions..........................      --        --         3       --
  Benefits paid......................................     (13)      (45)       (7)      (6)
  Transfer of plan assets............................  (1,679)       --        --       --
                                                       ------    ------      ----     ----
  Fair value of plan assets at end of period.........  $   97    $1,971      $ 40     $ 35
                                                       ======    ======      ====     ====
Reconciliation of funded status
  Funded status at end of period.....................  $   13    $1,149      $(69)    $(79)
  Fourth quarter contributions.......................      --                   3
  Unrecognized net actuarial gain....................      14      (528)      (28)     (27)
  Unrecognized net transition obligation.............      --       (12)       --       71
  Unrecognized prior service cost....................      --         4        --        3
  Other..............................................       1        --        --       --
                                                       ------    ------      ----     ----
  Accrued benefit cost at December 31, ..............  $   28    $  613      $(94)    $(32)
                                                       ======    ======      ====     ====
</Table>

<Table>
<Caption>
                                                   PENSION            POSTRETIREMENT
                                                   BENEFITS              BENEFITS
                                             --------------------   ------------------
                                                      YEAR ENDED DECEMBER 31,
                                             -----------------------------------------
                                             2001   2000    1999    2001   2000   1999
                                             ----   -----   -----   ----   ----   ----
                                                           (IN MILLIONS)
<S>                                          <C>    <C>     <C>     <C>    <C>    <C>
Benefit cost for the plans includes the
  following components
  Service cost............................   $  5   $  21   $  21   $ 1    $ 3    $ 3
  Interest cost...........................     20      59      52     9      8      7
  Expected return on plan assets..........    (55)   (164)   (146)   (2)    (1)    (1)
  Amortization of net actuarial gain......     (9)    (20)    (13)   --     (2)    (2)
  Amortization of transition obligation...     (2)     (8)     (8)   --      6      6
  Amortization of prior service cost......     --       1       1    --      1     --
  Curtailment and special termination
     benefit..............................    137      --      --    65     --     --
                                             ----   -----   -----   ---    ---    ---
  Net benefit cost........................   $ 96   $(111)  $ (93)  $73    $15    $13
                                             ====   =====   =====   ===    ===    ===
</Table>

     Benefit obligations are based upon actuarial estimates as described below.

<Table>
<Caption>
                                                                            POSTRETIREMENT
                                                        PENSION BENEFITS       BENEFITS
                                                        ----------------    --------------
                                                         2001      2000     2001     2000
                                                        ------    ------    -----    -----
<S>                                                     <C>       <C>       <C>      <C>
Weighted average assumptions
  Discount rate.......................................   7.25%     7.75%    7.25%    7.75%
  Expected return on plan assets......................  10.00%    10.00%    7.50%    4.60%
  Rate of compensation increase.......................   4.00%     4.00%      --       --
</Table>

                                        60
<PAGE>

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

<Table>
<Caption>
                                                              2001    2000
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
One Percentage Point Increase
  Aggregate of service cost and interest cost...............  $ --    $ --
  Accumulated postretirement benefit obligation.............  $  3    $  6
One Percentage Point Decrease
  Aggregate of service cost and interest cost...............  $ --    $ --
  Accumulated postretirement benefit obligation.............  $ (3)   $ (6)
</Table>

15. SEGMENT AND GEOGRAPHIC REPORTING

     Our business activities are segregated into four segments: Pipelines,
Merchant Energy, Production 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 historical segments (natural gas systems;
refining, marketing and chemicals; exploration and production; power; and coal)
have been restated and included in the segments in which these businesses were
managed and operated following the merger. All prior periods have been restated
to reflect this presentation. The results presented in this analysis are not
necessarily indicative of the results that would have been achieved had the
revised business segment structure been in effect during those periods.

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

     Our Merchant Energy segment is involved in a broad range of energy-related
activities, including asset ownership and marketing and trading activities. We
buy, sell and trade natural gas, power, crude oil, refined products, coal and
other energy commodities and own or have interests in 18 power generation plants
in 8 countries.

     Our Production segment is engaged in the exploration for and the
acquisition, development and production of natural gas, oil and natural gas
liquids, primarily in North America. Production has onshore and coal seam
operations and properties in 14 states and offshore operations and properties in
federal and state waters in the Gulf of Mexico. Internationally, we have
exploration and production rights in Australia, Bolivia, Brazil, Canada, Hungary
and Indonesia.

     Our Field Services segment provides wellhead-to-mainline services,
including natural gas gathering, products extraction, fractionation,
dehydration, purification, compression and transportation of natural gas and
natural gas liquids. Field Services' assets are located in the Rocky Mountains,
east and south Texas and Louisiana.

     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 have chosen to evaluate
segment performance based on EBIT instead of operating income. To the extent
practicable, results of operations for the years ended December 31, 2000 and
1999 have been reclassified to conform to the current business segment
presentation, although such results are not necessarily indicative of

                                        61
<PAGE>

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    PRODUCTION   SERVICES   OTHER(1)()    TOTAL
                                           ---------   --------   ----------   --------   ----------   -------
                                                                      (IN MILLIONS)
<S>                                        <C>         <C>        <C>          <C>        <C>          <C>
Revenues from external customers
  Domestic...............................   $  980     $18,063      $1,772       $822        $ 355     $21,992
  Foreign................................        2       3,662          46          4           --       3,714
Intersegment revenue.....................       70         335         (35)        68         (438)         --
Merger-related costs and asset impairment
  charges................................      217         169          61         13          526         986
Ceiling test charges.....................       --          --         115         --           --         115
Depreciation, depletion and
  amortization...........................      137         103         453         15           21         729
Operating income (loss)..................      192        (210)        785         55         (710)        112
Other income.............................      100         199           6         16           12         333
EBIT.....................................      292         (11)        791         71         (698)        445
Extraordinary items, net of income
  taxes..................................       --          (7)         --         (4)          --         (11)
Assets
  Domestic...............................    5,467       2,845       5,761        529          197      14,799
  Foreign................................       14       3,431         773         17           32       4,267
Capital expenditures and investments in
  unconsolidated affiliates..............      421         333       1,814         53            1       2,622
Total investments in unconsolidated
  affiliates.............................      547       1,041         110        168           17       1,883
</Table>

<Table>
<Caption>
                                                                       SEGMENTS
                                                     AS OF OR FOR THE YEAR ENDED DECEMBER 31, 2000
                                           -----------------------------------------------------------------
                                                       MERCHANT                 FIELD
                                           PIPELINES    ENERGY    PRODUCTION   SERVICES   OTHER(1)    TOTAL
                                           ---------   --------   ----------   --------   --------   -------
                                                                     (IN MILLIONS)
<S>                                        <C>         <C>        <C>          <C>        <C>        <C>
Revenues from external customers
  Domestic...............................   $  972     $19,981      $  806       $709      $1,191    $23,659
  Foreign................................       --       3,270           5          2          --      3,277
Intersegment revenue.....................       73         334         320         44        (771)        --
Merger-related costs and asset impairment
  charges................................       --          21          --         --          13         34
Depreciation, depletion and
  amortization...........................      132          88         399          8          30        657
Operating income.........................      388         118         417         86          44      1,053
Other income (loss)......................      112         248          (4)        25          34        415
EBIT.....................................      500         366         413        111          78      1,468
Assets
  Domestic...............................    5,182       5,278       4,038        512       1,424     16,434
  Foreign................................       83       2,086         198         17          57      2,441
Capital expenditures and investments in
  unconsolidated affiliates..............      232         229       1,583         45          23      2,112
Total investments in unconsolidated
  affiliates.............................      609         794          --        193          17      1,613
</Table>

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

(1) Includes Corporate and eliminations as well as retail operations.

                                        62
<PAGE>

<Table>
<Caption>
                                                                       SEGMENTS
                                                     AS OF OR FOR THE YEAR ENDED DECEMBER 31, 1999
                                           -----------------------------------------------------------------
                                                       MERCHANT                 FIELD
                                           PIPELINES    ENERGY    PRODUCTION   SERVICES   OTHER(1)    TOTAL
                                           ---------   --------   ----------   --------   --------   -------
                                                                     (IN MILLIONS)
<S>                                        <C>         <C>        <C>          <C>        <C>        <C>
Revenues from external customers
  Domestic...............................   $  919     $11,879      $  576       $276      $1,049    $14,699
  Foreign................................       --       1,889           8         --          --      1,897
Intersegment revenue.....................       67         359          28         25        (479)        --
Depreciation, depletion and
  amortization...........................      133          84         239          7          30        493
Operating income.........................      385          93         171         33          61        743
Other income.............................       96         166           1         12          10        285
EBIT.....................................      481         259         172         45          71      1,028
Assets
  Domestic...............................    5,116       3,456       2,959        385       1,253     13,169
  Foreign................................       53       2,055          74         --          72      2,254
Capital expenditures and investments in
  unconsolidated affiliates..............      230         351       1,082         77          41      1,781
Total investments in unconsolidated
  affiliates.............................      602         663          --        172          (2)     1,435
</Table>

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

(1) Includes Corporate and eliminations as well as retail operations.

     The reconciliations of EBIT to income before extraordinary items are
presented below for the years ended December 31:

<Table>
<Caption>
                                                            2001      2000      1999
                                                            -----    ------    ------
                                                                  (IN MILLIONS)
<S>                                                         <C>      <C>       <C>
Total EBIT for segments...................................  $ 445    $1,468    $1,028
Non-affiliated interest and debt expense..................   (447)     (502)     (323)
Affiliated interest expense, net..........................    (46)       --        --
Minority interest.........................................    (51)      (60)      (32)
Income taxes..............................................    (78)     (252)     (174)
                                                            -----    ------    ------
          Income (loss) before extraordinary items........  $(177)   $  654    $  499
                                                            =====    ======    ======
</Table>

     We had no customers whose revenues exceeded 10 percent of our total
revenues in 2001, 2000 and 1999.

16. 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.............................................  $ 589    $  389    $  307
Income tax payments.......................................     77        70        10
</Table>

                                        63
<PAGE>

17. 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 $22 million and $20 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>
United States
  Alliance Pipeline Limited
     Partnership.....................                14%       $  160   $  216   $--    $--
  Aux Sable Liquid...................                14%           58       56    --     --
  Bastrop Company, LLC...............                50%           99       33    --     --
  Eagle Point Cogeneration
     Partnership.....................                84%           85       34    --     --
  Great Lakes Gas Transmission LP....                50%          297      291    --     --
  Javelina Company...................                40%           48       55    --     --
  Midland Cogeneration Venture.......                44%          276      198    --     --
  Noric Holdings I, LLC(1)...........                41%          110       --    --     --
  Other Domestic Investments(2)......              various        297      293    --     --
                                                               ------   ------   ---    ---
          Total United States...............................    1,430    1,176    --     --
                                                               ------   ------   ---    ---
Foreign
  EGE Fortuna........................   Panama       24%           56       53    --     --
  Empresa Generadora de Electridad
     (Itabo).........................  Dominican     25%          101       99    --     --
                                       Republic
  Habibullah Power...................  Pakistan      50%           53       53    --     --
  Other Foreign Investments(1).......              various        243      232    59     72
                                                               ------   ------   ---    ---
          Total Foreign.....................................      453      437    59     72
                                                               ------   ------   ---    ---
          Total investments in and
            advances to unconsolidated
            affiliates......................................   $1,883   $1,613   $59    $72
                                                               ======   ======   ===    ===
</Table>

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

(1) In June 2001, we conveyed oil and gas properties to an affiliate for an
    equity investment of 26 percent. In December 2001, we conveyed additional
    properties which increased our ownership percentage to 41 percent.

(2) Denotes investments less than $50 million.

                                        64
<PAGE>

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

<Table>
<Caption>
                                                              2001    2000    1999
                                                              ----    ----    ----
                                                                 (IN MILLIONS)
<S>                                                           <C>     <C>     <C>
Alliance Pipeline Limited Partnership.......................  $ 23    $ 12    $ 10
Eagle Point Cogeneration Partnership........................    22      25      22
Empire State Pipeline.......................................     3       8       9
Empresa Generadora de Electricidad (Itabo)..................     5       9       3
Engage Energy US, LP and Engage Energy Canada, LP (through
  September 2000)...........................................    --      11       5
Great Lakes Gas Transmission LP.............................    55      52      52
Iroquois Gas Pipeline System, LP............................     3       7       6
Javelina Company............................................    (1)     17      10
Midland Cogeneration Venture................................    23      37      16
Mohawk River Funding IV, LLC................................    47      --      --
Noric Holdings I, LLC.......................................     4      --      --
Other.......................................................    39      87      57
                                                              ----    ----    ----
                                                              $223    $265    $190
                                                              ====    ====    ====
</Table>

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

     In October 2000, we terminated the Engage joint venture that was formed in
1997. As a result, the operations were divided into separate entities that are
owned and operated independently by each former joint venture partner.

     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 $38 million and $48
million for December 31, 2001 and 2000 and total assets of $760 million and $542
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..............................  $1,326    $3,829    $3,345
  Costs and expenses.....................................   1,103     3,459     3,107
  Income from continuing operations......................     223       370       238
  Net income.............................................     223       241       196
</Table>

<Table>
<Caption>
                                                                 DECEMBER 31,
                                                              ------------------
                                                               2001       2000
                                                              -------    -------
                                                                 (UNAUDITED)
                                                                (IN MILLIONS)
<S>                                                           <C>        <C>
Financial position data:
  Current assets............................................  $   576    $   717
  Non-current assets........................................    3,508      3,288
  Short-term debt...........................................      228        207
  Other current liabilities.................................      249        412
  Long-term debt............................................    1,524      1,654
  Other non-current liabilities.............................      279        123
  Equity in net assets......................................    1,804      1,609
</Table>

                                        65
<PAGE>

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

<Table>
<Caption>
                                                               2001     2000    1999
                                                              ------   ------   ----
                                                                  (IN MILLIONS)
<S>                                                           <C>      <C>      <C>
Revenues....................................................  $1,880   $1,154   $559
Cost of sales...............................................     248      314    140
Reimbursement for costs.....................................       3        4      4
Charges from affiliates.....................................     337       --     --
Capitalization of charges from affiliates...................      50       --     --
</Table>

     We enter into transactions with other El Paso subsidiaries and
unconsolidated affiliates in the ordinary course of business to transport, sell
and purchase natural gas and various contractual agreements for trading
activities. Prior to October 2000, we had significant activities with Engage
Energy. During the fourth quarter of 2000, we terminated the Engage joint
venture and assumed the U.S. portion of Engage. In February 2001, we transferred
our natural gas and power trading activities to El Paso Merchant Energy, an
affiliate and subsidiary of El Paso, in exchange for a 22 percent interest in El
Paso Merchant Energy, L.P. The transfer was based on estimated fair value of
contracts transferred, and the investment was accounted for on a cost basis. In
September 2001, we redeemed this interest. As a result, operational related
party transactions that had previously been with an unconsolidated affiliate are
now with an affiliate. In addition, other operational affiliated transactions
have increased due to the El Paso merger.

     As a result of the El Paso merger, during 2001, El Paso and its
subsidiaries provided some operational, financial, accounting and administrative
services for 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. We believe the allocation methods are reasonable. Our Production
segment capitalizes a portion of the allocated costs to the full cost pool based
on net property, and it is reflected as a reduction of operation expenses.

     Effective with the merger with El Paso, we now 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 $932 million at December 31, 2001, at a market rate of
interest which was 2.1%. In addition, we have a demand note receivable with El
Paso of $120 million at December 31, 2001, with an interest rate of 4.2%.

     At December 31, 2001, we had current account and note receivables from
related parties of $426 million and $88 million at December 31, 2000. In
addition, we had a non-current note receivable of $27 million included in other
non-current assets at December 31, 2001, and $31 million at December 31, 2000.
Also, at December 31, 2001, we had account and note payables from related
parties of $428 million and $13 million at December 31, 2000.

                                        66
<PAGE>

18. 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(1).....................     $5,520         $6,415        $5,974     $7,797
  Merger-related costs and asset impairment
     charges................................        (13)            15           217        767
  Ceiling test charges......................         --            115            --         --
  Operating income (loss)(1)................        304            126           (18)      (300)
  Income (loss) before extraordinary
     items..................................        188             40           (68)      (337)
  Extraordinary items, net of income
     taxes..................................         --             (4)            3        (10)
  Net income (loss).........................        188             36           (65)      (347)
2000
  Operating revenues........................     $8,748         $6,450        $6,123     $5,615
  Merger-related costs and asset impairment
     charges................................         24              3             3          4
  Operating income..........................        299            272           219        263
  Income before extraordinary items.........        207            145           128        174
  Net income................................        207            145           128        174
</Table>

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

(1) Adjustments were made to conform our accounting presentation to El Paso's
    presentation and include reclassifications to conform to El Paso's current
    presentation. These reclassifications had no impact on our net income or
    retained earnings.

19. SUPPLEMENTAL NATURAL GAS AND OIL OPERATIONS (UNAUDITED)

     At December 31, 2001, we had interests in natural gas and oil properties in
14 states and offshore operations and properties in federal and state waters in
the Gulf of Mexico. Internationally, we have a limited number of natural gas and
oil properties in Brazil, Canada and Indonesia as well as exploration and
production rights in Australia, Bolivia, Brazil, Canada, Hungary and Indonesia.

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

                                        67
<PAGE>

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

<Table>
<Caption>
                                                       UNITED               OTHER
                                                       STATES   CANADA   COUNTRIES(1)   WORLDWIDE
                                                       ------   ------   ------------   ---------
<S>                                                    <C>      <C>      <C>            <C>
2001
  Natural gas and oil properties:
    Costs subject to amortization....................  $6,394    $415        $ 72        $6,881
    Costs not subject to amortization................     494     250          49           793
                                                       ------    ----        ----        ------
                                                        6,888     665         121         7,674
Less accumulated DD&A................................   2,316     170          31         2,517
                                                       ------    ----        ----        ------
Net capitalized costs................................  $4,572    $495        $ 90        $5,157
                                                       ======    ====        ====        ======
2000
  Natural gas and oil properties:
    Costs subject to amortization....................  $4,168    $114        $ --        $4,282
    Costs not subject to amortization................     667      32          12           711
                                                       ------    ----        ----        ------
                                                        4,835     146          12         4,993
Less accumulated DD&A................................     985       1          --           986
                                                       ------    ----        ----        ------
Net capitalized costs................................  $3,850    $145        $ 12        $4,007
                                                       ======    ====        ====        ======
</Table>

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

(1) Includes International operations in Brazil and Indonesia.

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

<Table>
<Caption>
                                                       UNITED               OTHER
                                                       STATES   CANADA   COUNTRIES(1)   WORLDWIDE
                                                       ------   ------   ------------   ---------
<S>                                                    <C>      <C>      <C>            <C>
2001
  Property acquisition costs
    Proved properties................................  $   87    $232        $--         $  319
    Unproved properties..............................      33      16         25             74
  Exploration costs..................................     110      19         58            187
  Development costs..................................   1,025     105         14          1,144
                                                       ------    ----        ---         ------
         Total costs incurred                          $1,255    $372        $97         $1,724
                                                       ======    ====        ===         ======
2000
  Property acquisition costs
    Proved properties................................  $  127    $  3        $--         $  130
    Unproved properties..............................     130       6         --            136
  Exploration costs..................................     193      42         11            246
  Development costs..................................     961      69         --          1,030
                                                       ------    ----        ---         ------
         Total costs incurred                          $1,411    $120        $11         $1,542
                                                       ======    ====        ===         ======
1999
  Property acquisition costs
    Proved properties................................  $  154    $ --        $--         $  154
    Unproved properties..............................     142      10         --            152
  Exploration costs..................................     150      11         --            161
  Development costs..................................     588       5         --            593
                                                       ------    ----        ---         ------
         Total costs incurred                          $1,034    $ 26        $--         $1,060
                                                       ======    ====        ===         ======
</Table>

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

(1) Includes International operations in Brazil and Indonesia.

     Presented below is an analysis of the capitalized costs of natural gas and
oil properties by year of expenditure that are not being amortized as of
December 31, 2001, pending determination of proved reserves.

                                        68
<PAGE>

Capitalized interest of $47 million, $25 million, and $2 million for the years
ended December 31, 2001, 2000 and 1999 is included in the presentation below (in
millions):

<Table>
<Caption>
                                            CUMULATIVE    COSTS EXCLUDED FOR    CUMULATIVE
                                             BALANCE         YEARS ENDED         BALANCE
                                           DECEMBER 31,      DECEMBER 31,      DECEMBER 31,
                                           ------------   ------------------   ------------
                                               2001       2001   2000   1999       1998
                                           ------------   ----   ----   ----   ------------
<S>                                        <C>            <C>    <C>    <C>    <C>
Worldwide
  Acquisition............................      $599       $330   $110   $ 70       $ 89
  Exploration............................        88         27     46     11          4
  Development............................       106         30     35     23         18
                                               ----       ----   ----   ----       ----
                                               $793       $387   $191   $104       $111
                                               ====       ====   ====   ====       ====
</Table>

     Projects presently excluded from amortization are in various stages of
evaluation. The majority of these costs are expected to be included in the
amortization calculation in the years 2002 through 2005. Total amortization
expense per Mcfe, including ceiling test charges, was $1.29, $1.05, and $0.87 in
2001, 2000, and 1999. Excluding ceiling test charges, amortization expense would
have been $1.03 per Mcfe in 2001. Depreciation, depletion, and amortization
excludes provisions for the impairment of international projects of $15 million
in 2000 and $10 million in 1999.

     Net quantities of proved developed and undeveloped reserves of natural gas
and liquids, including condensate and crude oil, and changes in these reserves
are presented below. These reserves include 124,158, 197,782 and 259,342 MMcfe
of production delivery commitments under financing arrangements that extend
through 2005. Total proved reserves on the fields with this dedicated production
were 1,981,239 MMcfe.

<Table>
<Caption>
                                                                NATURAL GAS (IN BCF)
                                               -------------------------------------------------------
                                                                                             NATURAL
                                               UNITED               OTHER                      GAS
                                               STATES   CANADA   COUNTRIES(1)   WORLDWIDE   SYSTEMS(2)
                                               ------   ------   ------------   ---------   ----------
<S>                                            <C>      <C>      <C>            <C>         <C>
Net proved developed and undeveloped
  reserves(3)
  January 1, 1999............................  2,316       --         --          2,316        212
     Revisions of previous estimates.........    (61)      --         --            (61)        22
     Extensions, discoveries and other.......    746       73         --            819         --
     Purchases of reserves in place..........    539       --         --            539         --
     Sales of reserves in place..............    (40)      --         --            (40)        --
     Production..............................   (231)      --         --           (231)       (36)
                                               -----     ----        ---         ------        ---
  December 31, 1999..........................  3,269       73         --          3,342        198
     Revisions of previous estimates.........   (203)     (62)        --           (265)        11
     Extensions, discoveries and other.......    802      155         91          1,048         --
     Purchases of reserves in place..........    499        2         --            501         --
     Sales of reserves in place..............    (19)      --         --            (19)        --
     Production..............................   (328)      (1)        --           (329)       (33)
                                               -----     ----        ---         ------        ---
  December 31, 2000..........................  4,020      167         91          4,278        176
     Revisions of previous estimates.........   (996)    (136)       (51)        (1,183)        37
     Extensions, discoveries and other.......    604       85         --            689         --
     Purchases of reserves in place..........    103       83         --            186         --
     Sales of reserves in place..............     --       --         --             --         --
     Production..............................   (373)     (13)        --           (386)       (30)
                                               -----     ----        ---         ------        ---
  December 31, 2001..........................  3,358      186         40          3,584        183
                                               =====     ====        ===         ======        ===
Proved developed reserves
     December 31, 1999.......................  1,626       27         --          1,653        198
     December 31, 2000.......................  1,816      112         --          1,928        176
     December 31, 2001.......................  1,613      138         --          1,751        183
</Table>

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

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

                                        69
<PAGE>

<Table>
<Caption>
                                                                   LIQUIDS(1) (IN MBBLS)
                                                  --------------------------------------------------------
                                                                                                 NATURAL
                                                  UNITED                OTHER                      GAS
                                                  STATES    CANADA   COUNTRIES(2)   WORLDWIDE   SYSTEMS(3)
                                                  -------   ------   ------------   ---------   ----------
<S>                                               <C>       <C>      <C>            <C>         <C>
Net proved developed and undeveloped reserves(4)
  January 1, 1999...............................   52,047       --          --        52,047        237
     Revisions of previous estimates............   (6,620)      --          --        (6,620)        36
     Extensions, discoveries and other..........    5,354      867          --         6,221         --
     Purchases of reserves in place.............   11,377       --          --        11,377         --
     Sales of reserves in place.................     (805)      --          --          (805)        --
     Production.................................   (4,475)      --          --        (4,475)       (24)
                                                  -------   ------      ------       -------       ----
  December 31, 1999.............................   56,878      867          --        57,745        249
     Revisions of previous estimates............      238     (544)         --          (306)         7
     Extensions, discoveries and other..........    8,231    3,600       4,862        16,693         --
     Purchases of reserves in place.............    6,546       13          --         6,559         --
     Sales of reserves in place.................     (609)      --          --          (609)        --
     Production.................................   (6,477)     (13)         --        (6,490)       (25)
                                                  -------   ------      ------       -------       ----
  December 31, 2000.............................   64,807    3,923       4,862        73,592        231
     Revisions of previous estimates............   25,140   (4,224)     (4,862)       16,054       (118)
     Extensions, discoveries and other..........   24,843    1,173       7,771        33,787         --
     Purchases of reserves in place.............      101   10,570          --        10,671         --
     Sales of reserves in place.................       --       --          --            --         --
     Production.................................   (8,227)    (560)         --        (8,787)       (16)
                                                  -------   ------      ------       -------       ----
  December 31, 2001.............................  106,664   10,882       7,771       125,317         97
                                                  =======   ======      ======       =======       ====
Proved developed reserves
     December 31, 1999..........................   33,690      312          --        34,002        249
     December 31, 2000..........................   36,404    2,723          --        39,127        231
     December 31, 2001..........................   62,704    7,341          --        70,045         97
</Table>

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

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

     There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures, including many factors beyond our control. The reserve
data represents only estimates. Reservoir engineering is a subjective process of
estimating underground accumulations of natural gas and oil that cannot be
measured in an exact manner.

     The significant changes to reserves, other than purchases, sales or
production, are due to reservoir performance in existing fields and from
drilling additional wells in existing fields. There have been no major
discoveries or other events, favorable or adverse, that may be considered to
have caused a significant change in the estimated proved reserves since December
31, 2001.

                                        70
<PAGE>

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

<Table>
<Caption>
                                                       UNITED                OTHER
                                                       STATES    CANADA   COUNTRIES(1)   WORLDWIDE
                                                       ------    ------   ------------   ---------
<S>                                                    <C>       <C>      <C>            <C>
2001
Net Revenues
  Sales to external customers........................  $  391     $ 45        $ --        $  436
  Affiliated sales...................................   1,484        1          --         1,485
                                                       ------     ----        ----        ------
         Total.......................................   1,875       46          --         1,921
Production costs.....................................    (210)     (12)         --          (222)
Depreciation, depletion and amortization.............    (435)     (17)         --          (452)
Ceiling test charges.................................      --      (87)        (28)         (115)
                                                       ------     ----        ----        ------
                                                        1,230      (70)        (28)        1,132
Income tax (expense) benefit.........................    (430)      25          (9)         (414)
                                                       ------     ----        ----        ------
Results of operations from producing activities
  (excluding corporate overhead and interest
  costs).............................................  $  800     $(45)       $(37)       $  718
                                                       ======     ====        ====        ======
2000
Net Revenues
  Sales to external customers........................  $  867     $  6        $ --        $  873
  Affiliated sales...................................     214       --          --           214
                                                       ------     ----        ----        ------
         Total.......................................   1,081        6          --         1,087
Production costs.....................................    (236)      (1)         --          (237)
Depreciation, depletion and amortization.............    (372)      (1)         --          (373)
                                                       ------     ----        ----        ------
                                                          473        4          --           477
Income tax (expense) benefit.........................    (160)      (2)         --          (162)
                                                       ------     ----        ----        ------
Results of operations from producing activities
  (excluding corporate overhead and interest
  costs).............................................  $  313     $  2        $ --        $  315
                                                       ======     ====        ====        ======
1999
Net Revenues
  Sales to external customers........................  $  451     $ --        $ --        $  451
  Affiliated sales...................................     113       --          --           113
                                                       ------     ----        ----        ------
         Total.......................................     564       --          --           564
Production costs.....................................    (154)      --          --          (154)
Depreciation, depletion and amortization.............    (223)      --          --          (223)
                                                       ------     ----        ----        ------
                                                          187       --          --           187
Income tax (expense) benefit.........................     (59)      --          --           (59)
                                                       ------     ----        ----        ------
Results of operations from producing activities
  (excluding corporate overhead and interest
  costs).............................................  $  128     $ --        $ --        $  128
                                                       ======     ====        ====        ======
</Table>

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

(1) Includes international operations in Brazil and Indonesia.

                                        71
<PAGE>

     The standardized measure of discounted future net cash flows relating to
proved natural gas and oil reserves follows at December 31 (in millions):

<Table>
<Caption>
                                                                                          NATURAL
                                         UNITED                  OTHER                      GAS
                                         STATES     CANADA    COUNTRIES(1)   WORLDWIDE   SYSTEMS(2)
                                         -------    -------   ------------   ---------   ----------
<S>                                      <C>        <C>       <C>            <C>         <C>
2001
Future cash inflows....................  $10,499    $   641     $   253       $11,393     $   313
Future production and development
  costs................................   (3,083)      (279)       (124)       (3,486)        (64)
Future income tax expenses.............   (1,675)        (8)        (23)       (1,706)        (83)
                                         -------    -------     -------       -------     -------
Future net cash flows..................    5,741        354         106         6,201         166
10% annual discount for estimated
  timing of cash flows.................   (2,380)      (143)        (52)       (2,575)        (72)
                                         -------    -------     -------       -------     -------
Standardized measure of discounted
  future net cash flows................  $ 3,361    $   211     $    54       $ 3,626     $    94
                                         =======    =======     =======       =======     =======
2000
Future cash inflows....................  $27,535    $ 1,597     $   397       $29,529     $   474
Future production and development
  costs................................   (5,064)      (171)       (209)       (5,444)       (110)
Future income tax expenses.............   (7,014)      (599)        (60)       (7,673)       (116)
                                         -------    -------     -------       -------     -------
Future net cash flows..................   15,457        827         128        16,412         248
10% annual discount for estimated
  timing of cash flows.................   (6,522)      (469)       (109)       (7,100)        (89)
                                         -------    -------     -------       -------     -------
Standardized measure of discounted
  future net cash flows................  $ 8,935    $   358     $    19       $ 9,312     $   159
                                         =======    =======     =======       =======     =======
1999
Future cash inflows....................  $ 8,250    $    --     $    --       $ 8,250     $   229
Future production and development
  costs................................   (2,674)        --          --        (2,674)        (74)
Future income tax expenses.............   (1,265)        --          --        (1,265)        (49)
                                         -------    -------     -------       -------     -------
Future net cash flows..................    4,311         --          --         4,311         106
10% annual discount for estimated
  timing of cash flows.................   (1,556)        --          --        (1,556)        (41)
                                         -------    -------     -------       -------     -------
Standardized measure of discounted
  future net cash flows................  $ 2,755         --          --       $ 2,755     $    65
                                         =======    =======     =======       =======     =======
</Table>

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

(1) Includes international operations in Brazil and Indonesia.
(2) Includes natural gas and oil properties owned by Colorado Interstate Gas
    Company and its subsidiaries.

     For the calculations in the preceding table, estimated future cash inflows
from estimated future production of proved reserves were computed using year-end
market natural gas and oil prices. We may receive amounts different than the
standardized measure of discounted cash flow for a number of reasons, including
price changes and the effects of our hedging activities.

     We do not rely upon the standardized measure when making investment and
operating decisions. These decisions are based on various factors including
probable and proved reserves, different price and cost assumptions, actual
economic conditions and corporate investment criteria.

                                        72
<PAGE>

     The following are the principal sources of change in the standardized
measure of discounted future net cash flows (in millions):

<Table>
<Caption>
                                                                YEARS ENDED DECEMBER 31,
                                       --------------------------------------------------------------------------
                                                  2001                      2000                    1999
                                       --------------------------   ---------------------   ---------------------
                                        EXPLORATION     NATURAL     EXPLORATION   NATURAL   EXPLORATION   NATURAL
                                            AND           GAS           AND         GAS         AND         GAS
                                       PRODUCTION(1)   SYSTEMS(2)   PRODUCTION    SYSTEMS   PRODUCTION    SYSTEMS
                                       -------------   ----------   -----------   -------   -----------   -------
<S>                                    <C>             <C>          <C>           <C>       <C>           <C>
Sales and transfers of natural gas
  and oil produced net of production
  costs..............................     $(1,699)      $  (255)      $(1,300)    $   (52)    $  (474)    $   (36)
Net changes in prices and production
  costs..............................      (7,659)           10         6,697         150         734          (6)
Extensions, discoveries and improved
  recovery, less related costs.......         767            --         3,586          --         606          --
Changes in estimated future
  development costs..................         (20)           13            --          --          --          --
Development costs incurred during the
  period.............................         338            --            83          --         102          --
Revisions of previous quantity
  estimates..........................      (1,188)           39          (693)         34        (235)         28
Accretion of discount................       1,308            23           194           4         136           7
Net change in income taxes...........       2,876            25        (3,337)        (42)       (307)          3
Purchases of reserves in place.......         223            --         1,292          --         643          --
Sales of reserves in place...........          --            --           (14)         --         (33)         --
Changes in production rates, timing
  and other..........................        (631)           80            49          --          --          --
                                          -------       -------       -------     -------     -------     -------
  Net change.........................     $(5,685)      $   (65)      $ 6,557     $    94     $ 1,172     $    (4)
                                          =======       =======       =======     =======     =======     =======
</Table>

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

(1) Includes operations in the United States, Canada, Brazil and Indonesia.
(2) Includes natural gas and oil properties owned by Colorado Interstate Gas
    Company and its subsidiaries.

                                        73
<PAGE>

                       REPORT OF INDEPENDENT ACCOUNTANTS

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

     In our opinion, the consolidated financial statements in the Index
appearing under Item 14(a)(1) present fairly, in all material respects, the
consolidated financial position of El Paso CGP Company as of December 31, 2001,
and the consolidated results of its operations and its cash flows for the year
then ended in conformity with accounting principles generally accepted in the
United States of America. In addition, in our opinion, the financial statement
schedule for the year ended December 31, 2001 listed in the index 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 the financial statement schedule are
the responsibility of the Company's management; our responsibility is to express
an opinion on these financial statements and the financial statement schedule
based on our audit. We conducted our audit 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 audit provides a
reasonable basis for our opinion.

     As discussed in Notes 1 and 8, the Company adopted Statement of Financial
Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging
Activities, on January 1, 2001.

     As discussed in Note 14, the Company changed the measurement dates used to
account for pensions and postretirement benefits other than pensions from
December 31 to September 30.

     We also audited the adjustments described in Note 15 that were applied to
restate the disclosures of 2000 and 1999 segment information in the accompanying
financial statements to give retroactive effect to the change in reportable
segments. In our opinion, such adjustments are appropriate and have been
properly applied to the prior period financial statements.

PricewaterhouseCoopers LLP

Houston, Texas
March 6, 2002

                                        74
<PAGE>

                          INDEPENDENT AUDITORS' REPORT

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

     We have audited the consolidated balance sheets of El Paso CGP Company
(formerly The Coastal Corporation) and subsidiaries as of December 31, 2000, and
the related consolidated statements of operations, stockholders' equity and cash
flows for each of the two years in the period ended December 31, 2000. Our
audits also included the financial statement schedule listed in the Index at
Item 14(a)2. These financial statements and financial statement schedule are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.

     We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

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

/s/ Deloitte & Touche LLP

Houston, Texas
March 19, 2001

                                        75
<PAGE>

                                  SCHEDULE II

                      EL PASO CGP COMPANY AND SUBSIDIARIES

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

<Table>
<Caption>
                                                 CHARGED TO
                                    BALANCE AT   COSTS AND                                       BALANCE
                                    BEGINNING     EXPENSES      CHARGED TO                       AT END
           DESCRIPTION              OF PERIOD    AND OTHER    OTHER ACCOUNTS   DEDUCTIONS       OF PERIOD
           -----------              ----------   ----------   --------------   ----------       ---------
<S>                                 <C>          <C>          <C>              <C>              <C>
2001
  Allowance for doubtful
     accounts.....................     $19          $ 23           $ --           $ (6)(1)        $ 36
  Legal reserves..................      32            50(2)          --             (1)             81
  Environmental reserves..........      28           242(2)          --            (10)            260
  Regulatory reserves.............      --             5             --             --               5
  Planned major maintenance
     accrual......................      51            (1)(3)         --            (14)             36
2000
  Allowance for doubtful
     accounts.....................     $32          $  3           $(14)          $ (2)(1)        $ 19
  Legal reserves..................      48           (14)(4)         --             (2)             32
  Environmental reserves..........      27            10             --             (9)             28
  Regulatory reserves.............       8             2             --            (10)             --
  Planned major maintenance
     accrual......................      34            33             --            (16)             51
1999
  Allowance for doubtful
     accounts.....................     $33          $  6           $ (6)          $ (1)(1)        $ 32
  Legal reserves..................      44             6             --             (2)             48
  Environmental reserves..........      30             1             --             (4)             27
  Regulatory reserves.............       6             2             --             --               8
  Planned major maintenance
     accrual......................      25            26             --            (17)             34
</Table>

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

(1) Primarily accounts written off.

(2) These amounts primarily relate to additional liabilities recorded in
    connection with changes in our estimates of these liabilities. See Note 4
    for a further discussion of this change.

(3) During 2001, we accrued $23 million of reserves. In June, we leased our
    Corpus Christi refinery to Valero, and as a result we reversed $24 million
    of reserves.

(4) Includes reversal of $16 million of legal reserves due to a favorable
    resolution of natural gas price-related contingencies.

                                        76
<PAGE>

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

     None.

                                    PART III

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

                                    PART IV

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

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

     1. Financial statements.

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

<Table>
<Caption>
                                                              PAGE
                                                              ----
<S>                                                           <C>
Consolidated Statements of Income...........................    31
Consolidated Balance Sheets.................................    32
Consolidated Statements of Cash Flows.......................    34
Consolidated Statements of Stockholders' Equity.............    35
Condensed Consolidated Statements of Comprehensive Income
  and Changes in Accumulated Other Comprehensive Income.....    36
Notes to Consolidated Financial Statements..................    37
Report of Independent Accountants...........................    74
</Table>

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

<Table>
<Caption>
                                                              PAGE
                                                              ----
<S>                                                           <C>
MOHAWK RIVER FUNDING IV, L.L.C.
  Report of Independent Accountants.........................    79
  Statement of Income.......................................    80
  Balance Sheet.............................................    81
  Statement of Cash Flows...................................    82
  Statement of Members' Capital.............................    83
  Notes to the Financial Statements.........................    84
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
  Independent Auditors' Report..............................    89
  Consolidated Statements of Income and Partners' Capital...    90
  Consolidated Balance Sheets...............................    91
  Consolidated Statements of Cash Flows.....................    92
  Notes to Consolidated Financial Statements................    93
</Table>

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

<Table>
<Caption>
                                                               PAGE
                                                               ----
<S>                                                            <C>
Schedule II  -- Valuation and qualifying accounts...........    76
</Table>

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

<Table>
<Caption>
                                                              PAGE
                                                              ----
<S>                                                           <C>  <C>
3. Exhibit list.............................................    96
</Table>

                                        77
<PAGE>

                        MOHAWK RIVER FUNDING IV, L.L.C.

                              FINANCIAL STATEMENTS
                     WITH REPORT OF INDEPENDENT ACCOUNTANTS
                               DECEMBER 31, 2001

                                        78
<PAGE>

                        MOHAWK RIVER FUNDING IV, L.L.C.

                       REPORT OF INDEPENDENT ACCOUNTANTS

To the Members of Mohawk River Funding IV, L.L.C.:

In our opinion, the accompanying balance sheet and the related statement of
income, of members' equity and of cash flows present fairly, in all material
respects, the financial position of Mohawk River Funding IV, L.L.C. (the
"Company", and formerly known as Poquonock River Funding, L.L.C.) at December
31, 2001, and the results of its operations and its cash flows for the period
from inception (August 2, 2001) to December 31, 2001, in conformity with
accounting principles generally accepted in the United States of America. These
financial statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based on
our audit. We conducted our audit 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 audit provides a
reasonable basis for our opinion.

As discussed in Note 3, the Company adopted Statement of Financial Accounting
Standards No. 133, Accounting for Derivative Instruments and Hedging Activities,
on the date of inception (August 2, 2001).

/s/ PricewaterhouseCoopers LLP

Houston, Texas
March 27, 2002

                                        79
<PAGE>

                        MOHAWK RIVER FUNDING IV, L.L.C.

                              STATEMENT OF INCOME

      FOR THE PERIOD FROM INCEPTION (AUGUST 2, 2001) TO DECEMBER 31, 2001
                                 (IN THOUSANDS)

<Table>
<S>                                                            <C>
Operating revenues
  Electricity sales.........................................   $  5,438
                                                               --------
Operating expenses
  Electricity purchases from affiliate......................      1,651
  Change in market value of power agreements, net...........      4,221
                                                               --------
                                                                  5,872
Operating loss..............................................       (434)
                                                               --------
Other income
  Initial market gain on power agreements, net..............     75,948
                                                               --------
Net income..................................................   $ 75,514
                                                               ========
</Table>

                            See accompanying notes.

                                        80
<PAGE>

                        MOHAWK RIVER FUNDING IV, L.L.C.

                                 BALANCE SHEET

                            AS OF DECEMBER 31, 2001
                                 (IN THOUSANDS)

<Table>
<S>                                                            <C>
                                ASSETS

Current assets
  Cash and cash equivalents.................................   $     --
  Amended power purchase agreement..........................     17,591
                                                               --------
          Total current assets..............................     17,591
  Amended power purchase agreement..........................     94,711
                                                               --------
          Total assets......................................   $112,302
                                                               ========

                   LIABILITIES AND MEMBERS' CAPITAL

Current liabilities
  Accounts payable -- affiliate.............................   $  1,651
  Accounts payable -- Connecticut Light and Power...........      8,767
  Mirror power purchase agreement -- affiliate..............      1,553
                                                               --------
          Total current liabilities.........................     11,971
Mirror power purchase agreement -- affiliate................      7,291
Commitments and contingencies
Members' capital............................................     93,040
                                                               --------
          Total liabilities and members' capital............   $112,302
                                                               ========
</Table>

                            See accompanying notes.

                                        81
<PAGE>

                        MOHAWK RIVER FUNDING IV, L.L.C.

                            STATEMENT OF CASH FLOWS

      FOR THE PERIOD FROM INCEPTION (AUGUST 2, 2001) TO DECEMBER 31, 2001
                                 (IN THOUSANDS)

<Table>
<S>                                                            <C>
Cash flows from operating activities
  Net income................................................   $ 75,514
  Adjustments to reconcile net income to net cash from
     operating activities:
     Initial market gain on power agreements, net...........    (75,948)
     Change in market value of power purchase agreements,
      net...................................................      4,221
     Working capital changes:
       Accounts payable -- affiliate........................      1,651
       Accounts payable -- Connecticut Light and Power......     (5,438)
                                                               --------
          Net cash provided from operating activities.......         --
                                                               --------
Net change in cash and cash equivalents.....................         --
Cash and cash equivalents
  Beginning of period.......................................         --
  End of period.............................................   $     --
                                                               ========
Non-cash transactions
  Contribution of power purchase agreement from members.....   $ 17,526
  Liability to Connecticut Light and Power..................     14,205
</Table>

                            See accompanying notes.

                                        82
<PAGE>

                        MOHAWK RIVER FUNDING IV, L.L.C.

                         STATEMENT OF MEMBERS' CAPITAL

      FOR THE PERIOD FROM INCEPTION (AUGUST 2, 2001) TO DECEMBER 31, 2001
                                 (IN THOUSANDS)

<Table>
<Caption>
                                                                             MESQUITE
                                                              ANR VENTURE   INVESTORS,    TOTAL
                                                              MANAGEMENT      L.L.C.     MEMBERS'
                                                                COMPANY       (50%)      CAPITAL
                                                              -----------   ----------   --------
<S>                                                           <C>           <C>          <C>
Initial contribution on August 2, 2001......................    $    --      $     1     $     1
Contribution receivable from member.........................         --           (1)         (1)
Contribution of power purchase agreement from member........         --       17,526      17,526
Net income..................................................     37,757       37,757      75,514
                                                                -------      -------     -------
December 31, 2001...........................................    $37,757      $55,283     $93,040
                                                                =======      =======     =======
</Table>

                            See accompanying notes.

                                        83
<PAGE>

                        MOHAWK RIVER FUNDING IV, L.L.C.

                       NOTES TO THE FINANCIAL STATEMENTS

1.  ORGANIZATION AND NATURE OF OPERATIONS

     We are a Delaware limited liability company (formerly known as Poquonock
River Funding, L.L.C.) organized in August 2001, under the terms of a limited
liability company agreement. We are jointly owned by ANR Venture Management
Company, a wholly owned subsidiary of El Paso Corporation, and Mesquite
Investors, L.L.C., an entity which is indirectly owned by Limestone Electron
Trust and El Paso. Our sole business is to sell electric energy and provide
electric capacity to The Connecticut Light and Power Company, a specially
chartered Connecticut corporation and public service company, under an amended
power purchase agreement that we entered into with Connecticut Light and Power.

     On October 19, 2001, one of our affiliates, Capitol District Energy Center
Cogeneration Association, a Connecticut joint venture, distributed its power
purchase agreement with Connecticut Light and Power to its members, ANR Venture
and Mesquite Investors. ANR Venture and Mesquite Investors immediately
contributed their interest in the power purchase agreement, which had an
aggregate book value of $17.5 million, to us. We amended the contributed power
purchase agreement and began operating under the amended power purchase
agreement on October 21, 2001. We do not have any employees and our operations
are carried out by El Paso Chaparral Management, L.P., a subsidiary of El Paso
Corporation, under a management agreement between El Paso Chaparral Management
and Mesquite Investors (see Note 5). We purchase the electric capacity and
electric energy necessary to meet our obligations under our amended power
purchase agreement from El Paso Merchant Energy, L.P., a wholly owned indirect
subsidiary of El Paso (see Note 4).

2.  LIMITED LIABILITY COMPANY

     As a limited liability company, our members are not personally obligated
for our debt, obligations, or other liabilities simply because they are our
members. These debts, obligations and other liabilities are solely ours.

3.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

  Basis of Presentation

     Our financial statements are prepared on the accrual basis of accounting in
accordance with accounting principles generally accepted in the United States.

  Use of Estimates

     The preparation of financial statements in accordance with generally
accepted accounting principles requires us to make estimates and assumptions
that affect the reported amounts of assets, liabilities, revenues and expenses
and disclosure of contingent assets and liabilities that exist at the date of
the financial statements. Actual results may differ from those estimates.

  Cash and Cash Equivalents

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

  Allowance for Doubtful Accounts

     We review collectibility of our accounts receivable on a regular basis
under the specific identification method. At December 31, 2001, no allowance for
doubtful accounts was recorded.

                                        84
<PAGE>
                        MOHAWK RIVER FUNDING IV, L.L.C.

                NOTES TO THE FINANCIAL STATEMENTS -- (CONTINUED)

  Income Taxes

     Since we are a limited liability company, income taxes accrue to our
members. As a result, we have not reflected a provision for income taxes in our
financial statements.

  Revenue Recognition

     We recognize revenue when we deliver electric energy and provide electric
capacity to Connecticut Light and Power. Revenue is based on the quantity of
electricity delivered and capacity provided at rates specified in our amended
power purchase agreement.

  Accounting for Derivative Instruments

     We record all derivative instruments on our balance sheet at their fair
value in accordance with Statement of Financial Accounting Standards (SFAS) No.
133, Accounting for Derivative Instruments and Hedging Activities as amended by
SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging
Activities. Our amended power purchase agreement and mirror power purchase
agreement qualify as derivative instruments under these standards. As a result,
they are recorded at their fair value in our balance sheet. Changes in the fair
value of these agreements are reported in our income statement as a change in
the market value of power agreements. We estimate the fair value of these
agreements based on an estimate of the cash receipts and payments under these
agreements using anticipated future power prices compared to the contractual
prices under these agreements, discounted at a risk-adjusted rate commensurate
with the term of each contract and the credit risk of each counterparty. Our
estimates of the timing of cash receipts and payments are based on the
anticipated timing of power delivered under these agreements. These estimates
also consider the minimum and maximum energy delivery requirements under those
agreements. Estimates of the future prices of power are based on the forward
pricing curve of the appropriate power delivery and receipt points, and this
curve is derived from the actual prices observed in the market, price quotes
from brokers and extrapolation models that rely on actively quoted prices and
historical information.

     As discussed above, our power purchase agreement was contributed to us by
our members and recorded initially at our members' cost of $17.5 million. The
cost represented Mesquite Investor's basis in the power purchase agreement as a
result of the acquisition of its interest in Capitol District Energy Center from
AE Fourteen, Inc., a subsidiary of Aetna Life Insurance Company. As
consideration for amending our power purchase agreement, we agreed to pay
Connecticut Light and Power $14.2 million. We also entered into the mirror power
purchase agreement with El Paso Merchant. Since these agreements qualify as
derivatives, our cost basis was adjusted to estimated fair value. We reflected
the difference between the carrying value of these agreements, and their
estimated market value as the initial market gain on power agreements of $75.9
million in our income statement. We included this amount as other income since
the initial market gain was incidental to the operation and execution of our
power purchase agreements. This initial gain is comprised of the initial value
of our amended power purchase agreement of $77.8 million, less the initial
market value of our mirror power purchase agreement of $1.9 million. Following
this initial valuation, changes in the fair values of these power purchase
agreements, which were $4.2 million through December 31, 2001, have been
reflected as a change in market value of power agreements in operating expenses.
These amounts are included in our operating income since changes in the value of
our power agreements result primarily from the execution of our obligations
under our power purchase agreements. See Note 4 for additional information on
the amended power purchase and mirror power purchase agreements.

4.  COMMITMENTS AND CONTINGENCIES

  Amended Power Purchase Agreement

     The amended power purchase agreement with Connecticut Light and Power
supercedes a pre-existing long-term power purchase agreement originally entered
into between Connecticut Light and Power and
                                        85
<PAGE>
                        MOHAWK RIVER FUNDING IV, L.L.C.

                NOTES TO THE FINANCIAL STATEMENTS -- (CONTINUED)

Capitol District Energy Center. The pre-existing long-term power purchase
agreement provided for the purchase by Connecticut Light and Power of electric
energy and electric capacity from Capitol District Energy Center. Through a
series of transactions, the pre-existing power purchase agreement was
distributed to our members who in turn contributed it to us. Upon the
contribution of the power purchase agreement, we amended its terms with
Connecticut Light and Power. Under this amended power purchase agreement, we are
required to arrange for electric capacity to be made available to Connecticut
Light and Power. Additionally, we will sell and deliver energy to Connecticut
Light and Power at specified delivery points, up to 45,000 kilowatt hours (kWh)
of energy during each hour of each on-peak period and up to 30,000 kWh of energy
during each hour of each off-peak period. We shall not schedule and deliver more
than 179,628 megawatt hours (MWh) of energy during the on-peak periods occurring
within any calendar year or 128,353 MWh of energy during the off-peak periods
occurring within any calendar year. For the period ended December 31, 2001, we
recorded electricity sales to Connecticut Light and Power of $5.4 million as
operating revenues.

     During each on-peak period of each summer period and winter period during
the delivery term, we are required to schedule and deliver enough energy during
such period so that the period performance factor, as defined in the amended
power purchase agreement, is greater than or equal to ninety-seven percent. If
we fail to meet these minimum on-peak deliveries, we shall pay Connecticut Light
and Power liquidated damages equal to the positive difference, if any, of (a)
the sum of the Aggregate New England Power Pool (NEPOOL) Deficiency Cost, as
defined in our amended power purchase agreement, for each hour during such
period minus (b) the sum of the Aggregate Contract Deficiency Cost, as defined
in our amended power purchase agreement, for each hour during such period.

     If we fail to deliver all or part of the scheduled energy for reasons other
than a force majeure event, we shall pay to Connecticut Light and Power
liquidated damages equal to the product of (a) the number of kWh we scheduled
but failed to deliver and (b) the positive difference, if any, of (i) the Final
Hourly Clearing Price for Energy, as defined in our amended power purchase
agreement, delivered at the delivery point with respect to each hour minus (ii)
the Energy Charge, as defined in the amended power purchase agreement, with
respect to such hour.

     If we fail to provide all or part of the required electric capacity for
reasons other than a force majeure event, we must pay to Connecticut Light and
Power a liquidated damages payment equal to the product of (a) the amount of
electric capacity we failed to provide in such month and (b) the positive
difference, if any, of (i) the applicable New England Independent System
Operator monthly electric capacity amount purchase Market Clearing Price minus
(ii) the electric capacity charge paid by Connecticut Light and Power, as
defined in the amended power purchase agreement.

     As incentive to enter into the amended power purchase agreement, we agreed
to pay Connecticut Light and Power $14.2 million, which amount is to be paid
through credits against invoices for power sold to Connecticut Light and Power.
The remaining liability at December 31, 2001 is $8.8 million.

  Mirror Power Purchase Agreement

     We have entered into a mirror power purchase agreement with El Paso
Merchant in order to have El Paso Merchant deliver to us the energy and electric
capacity that we are required to deliver to Connecticut Light and Power under
the amended power purchase agreement.

     Under the mirror power purchase agreement, El Paso Merchant must schedule
and deliver the required energy that we are obligated to deliver under the
amended power purchase agreement, and must make available to us electric
capacity credits equal to the electric capacity requirements under the amended
power purchase agreement. El Paso Merchant must schedule and deliver 179,628 MWh
of energy during the on-peak period of each calendar year and 128,353 MWh of
energy during the off-peak period of each calendar year. If El Paso Merchant
fails to deliver all or part of the scheduled energy to us, for any reason other
than a

                                        86
<PAGE>
                        MOHAWK RIVER FUNDING IV, L.L.C.

                NOTES TO THE FINANCIAL STATEMENTS -- (CONTINUED)

force majeure event, our payment to El Paso Merchant will be reduced by a credit
calculated in the same manner as the credit to Connecticut Light and Power
described in the amended power purchase agreement.

     If El Paso Merchant fails in any month to provide all or part of the
electric capacity, for any reason other than a force majeure event, our payment
to El Paso Merchant will be reduced by a credit calculated in the same manner as
the credit to Connecticut Light and Power as a direct result of our failure to
provide energy and electric capacity under the amended power purchase agreement.

5.  RELATED PARTY TRANSACTIONS

  Mirror Power Purchase Agreement

     El Paso Merchant provides electric energy and capacity to us under the
mirror power purchase agreement discussed above. Expenses under this agreement
are based on market rates at the time the agreement was negotiated. Total
purchases for the period ended December 31, 2001 were $1.7 million and have been
reflected as electricity purchases from affiliates in our income statement.
Amounts owed under the contract are reflected as an affiliate payable in our
balance sheet.

  Administrative Services

     Our operations are carried out by El Paso Chaparral Management under a
management agreement between El Paso Chaparral Management and Mesquite
Investors. El Paso Chaparral Management is responsible for our functions that
are normally considered part of the day-to-day administrative and management
activities, including financial, accounting, budgeting, tax services, general
legal and financial services, personnel administration, payroll services and
cash management services. The expenses paid by Mesquite Investors, under this
agreement, on our behalf, are immaterial and, as such, have not been allocated
on our behalf.

6.  CONCENTRATION OF CREDIT RISKS

     Our accounts receivable potentially subject us to credit risk. Our trade
receivables and revenues are solely from a single customer, Connecticut Light
and Power, which purchases electric energy and electric capacity from us under a
long-term power purchase agreement.

7.  FAIR VALUE OF FINANCIAL INSTRUMENTS

     As of December 31, 2001, the carrying amounts of our financial instruments
including cash, cash equivalents, and trade receivables and payables are
representative of fair value because of their short-term maturity.

                                        87
<PAGE>

                GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP

                              FINANCIAL STATEMENTS

                       WITH INDEPENDENT AUDITORS' REPORT

                               DECEMBER 31, 2001

                                        88
<PAGE>

                          INDEPENDENT AUDITORS' REPORT

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

     We have audited the accompanying consolidated balance sheets of Great Lakes
Gas Transmission Limited Partnership and subsidiary (Partnership) as of December
31, 2001 and 2000, and the related consolidated statements of income and
partners' capital, and cash flows for each of the years in the three year period
ended December 31, 2001. These consolidated financial statements are the
responsibility of the Partnership's management. Our responsibility is to express
an opinion on these consolidated financial statements based on our audits.

     We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

     In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Great Lakes
Gas Transmission Limited Partnership and subsidiary as of December 31, 2001 and
2000, and the results of their operations and their cash flows for each of the
years in the three year period ended December 31, 2001 in conformity with
accounting principles generally accepted in the United States of America.

/s/ KPMG LLP

Detroit, Michigan
January 9, 2002

                                        89
<PAGE>

                GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP

            CONSOLIDATED STATEMENTS OF INCOME AND PARTNERS' CAPITAL

<Table>
<Caption>
                                                                 YEARS ENDED DECEMBER 31,
                                                             --------------------------------
                                                               2001        2000        1999
                                                             ---------   ---------   --------
                                                                  (THOUSANDS OF DOLLARS)
<S>                                                          <C>         <C>         <C>
Transportation Revenues....................................  $ 276,872   $ 282,636   $283,287
Operating Expenses
  Operation and Maintenance................................     32,662      39,807     44,752
  Depreciation.............................................     56,640      60,705     58,821
  Income Taxes Payable by Partners.........................     39,950      39,518     40,032
  Property and Other Taxes.................................     28,828      29,322     26,725
                                                             ---------   ---------   --------
                                                               158,080     169,352    170,330
                                                             ---------   ---------   --------
Operating Income...........................................    118,792     113,284    112,957
Other Income (Expense)
  Interest on Long Term Debt...............................    (47,960)    (47,474)   (44,362)
  Allowance for Funds Used During Construction.............        464         769      1,837
  Other, Net...............................................      2,511       5,935      2,012
                                                             ---------   ---------   --------
                                                               (44,985)    (40,770)   (40,513)
                                                             ---------   ---------   --------
Net Income.................................................  $  73,807   $  72,514   $ 72,444
                                                             =========   =========   ========
Partners' Capital
  Balance at Beginning of Year.............................  $ 449,237   $ 604,838   $569,631
  Contributions by General Partners........................     21,226      19,290     21,966
  Net Income...............................................     73,807      72,514     72,444
  Current Income Taxes Payable by Partners Charged to
     Earnings..............................................     23,378      24,548     28,461
  Distributions to Partners................................   (124,008)   (271,953)   (87,664)
                                                             ---------   ---------   --------
  Balance at End of Year...................................  $ 443,640   $ 449,237   $604,838
                                                             =========   =========   ========
</Table>

        The accompanying notes are an integral part of these statements.

                                        90
<PAGE>

                GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP

                          CONSOLIDATED BALANCE SHEETS

<Table>
<Caption>
                                                                AS OF DECEMBER 31,
                                                              -----------------------
                                                                 2001         2000
                                                              ----------   ----------
                                                              (THOUSANDS OF DOLLARS)
<S>                                                           <C>          <C>
ASSETS
Current Assets
  Cash and Temporary Cash Investments.......................  $   40,320   $   39,940
  Receivable from Limited Partner...........................       1,922           --
  Accounts Receivable.......................................      29,145       35,311
  Materials and Supplies, at Average Cost...................      10,035       10,618
  Regulatory Assets.........................................         566        7,516
  Prepayments and Other.....................................       4,403        3,436
                                                              ----------   ----------
                                                                  86,391       96,821
                                                              ----------   ----------
Gas Utility Plant
  Property, Plant and Equipment.............................   1,965,442    1,946,348
  Less Accumulated Depreciation.............................     772,832      729,136
                                                              ----------   ----------
                                                               1,192,610    1,217,212
                                                              ----------   ----------
                                                              $1,279,001   $1,314,033
                                                              ==========   ==========

LIABILITIES & PARTNERS' CAPITAL
Current Liabilities
  Current Maturities of Long Term Debt......................  $   36,500   $   19,500
  Accounts Payable..........................................      14,344       20,011
  Payable to Limited Partner................................          --        1,526
  Property and Other Taxes..................................      27,895       29,340
  Accrued Interest and Other................................      13,421       16,293
                                                              ----------   ----------
                                                                  92,160       86,670
                                                              ----------   ----------
Long Term Debt..............................................     532,250      575,750
Other Liabilities
  Amounts Equivalent to Deferred Income Taxes...............     206,057      193,139
  Regulatory Liabilities....................................       3,870        5,287
  Other.....................................................       1,024        3,950
                                                              ----------   ----------
                                                                 210,951      202,376
                                                              ----------   ----------
Partners' Capital...........................................     443,640      449,237
                                                              ----------   ----------
                                                              $1,279,001   $1,314,033
                                                              ==========   ==========
</Table>

        The accompanying notes are an integral part of these statements.

                                        91
<PAGE>

                GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP

                     CONSOLIDATED STATEMENTS OF CASH FLOWS

<Table>
<Caption>
                                                                  YEARS ENDED DECEMBER 31,
                                                              --------------------------------
                                                                2001        2000        1999
                                                              ---------   ---------   --------
                                                                   (THOUSANDS OF DOLLARS)
<S>                                                           <C>         <C>         <C>
Cash Flow Increase (Decrease) from:
Operating Activities
  Net Income................................................  $  73,807   $  72,514   $ 72,444
  Adjustments to Reconcile Net Income to Operating Cash
     Flows:
     Depreciation...........................................     56,640      60,705     58,821
     Amounts Equivalent to Deferred Income Taxes............     12,918      15,411     12,286
     Regulatory Assets......................................      6,950       1,209     (1,333)
     Regulatory Liabilities.................................     (1,417)     (1,452)    (1,424)
     Allowance for Funds Used During Construction...........       (464)       (769)    (1,837)
     Changes in Current Assets and Liabilities:
       Accounts Receivable..................................      6,166      (1,289)    (6,774)
       Accounts Payable.....................................     (5,667)     (1,205)       662
       Property and Other Taxes.............................     (1,445)     (1,689)    (1,943)
       Other................................................     (9,630)        (52)    11,127
                                                              ---------   ---------   --------
                                                                137,858     143,383    142,029
Investment in Utility Plant.................................    (31,574)    (33,372)   (48,909)
Financing Activities
  Issuance of Long Term Debt................................         --     100,000         --
  Repayment of Long Term Debt...............................    (26,500)    (17,800)   (39,700)
  Contributions by Partners.................................     21,226      19,290     21,966
  Current Income Taxes Payable by Partners Charged to
     Earnings...............................................     23,378      24,548     28,461
  Distributions to Partners.................................   (124,008)   (271,953)   (87,664)
                                                              ---------   ---------   --------
                                                               (105,904)   (145,915)   (76,937)
                                                              ---------   ---------   --------
Change in Cash and Cash Equivalents.........................        380     (35,904)    16,183
Cash and Cash Equivalents:
  Beginning of Year.........................................     39,940      75,844     59,661
                                                              ---------   ---------   --------
  End of Year...............................................  $  40,320   $  39,940   $ 75,844
                                                              =========   =========   ========
Supplemental Disclosure of Cash Flow Information
  Cash Paid During the Year for Interest
     (Net of Amounts Capitalized of $206, $249 and $705,
       Respectively)........................................  $  48,197   $  44,199   $ 44,281
                                                              =========   =========   ========
</Table>

        The accompanying notes are an integral part of these statements.

                                        92
<PAGE>

                GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  ORGANIZATION AND MANAGEMENT

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

<Table>
<Caption>
                                                               OWNERSHIP %
                                                              -------------
                  PARTNER (PARENT COMPANY)                    2001    2000
                  ------------------------                    -----   -----
<S>                                                           <C>     <C>
General Partners:
  Coastal Great Lakes, Inc. (El Paso Corporation)...........  45.40   39.29
  TransCanada GL, Inc. (TransCanada PipeLines Ltd.).........  45.40   39.29
Limited Partner:
  Great Lakes Gas Transmission Company (TransCanada
  PipeLines Ltd. and El Paso Corporation)...................   9.20   21.42
</Table>

     Coastal Great Lakes, Inc. was formally owned by The Coastal Corporation
(Coastal), which merged into a subsidiary of El Paso Corporation (El Paso) on
January 29, 2001.

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

2.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

  Principles of Consolidation and Basis of Presentation

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

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

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

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

  Regulation

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

                                        93
<PAGE>
                GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

  Gas Utility Plant and Depreciation

     Gas utility plant is stated at cost and includes certain administrative and
general expenses, plus an allowance for funds used during construction. The cost
of plant retired is charged to accumulated depreciation. Depreciation of gas
utility plant is computed using the straight-line method. The Partnership's
principal operating assets were depreciated at an annual rate of 2.75% for 2001
and 3.00% for both 2000 and 1999.

     The allowance for funds used during construction represents the debt and
equity costs of capital funds applicable to utility plant under construction,
calculated in accordance with a uniform formula prescribed by the FERC. The rate
used in 2001, 2000 and 1999 were 10.36%, 10.95% and 10.84%, respectively.

  Income Taxes

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

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

3.  AFFILIATED COMPANY TRANSACTIONS

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

<Table>
<Caption>
                                                         2001       2000       1999
                                                       --------   --------   --------
                                                               (IN THOUSANDS)
<S>                                                    <C>        <C>        <C>
Accounts receivable..................................  $ 15,936   $ 17,447   $ 18,540
Transportation revenues:
  TransCanada PipeLines Ltd. and affiliates..........   176,818    185,912    185,566
  El Paso Corporation and affiliates.................    25,716         --         --
  The Coastal Corporation and affiliates.............        --     28,981     30,269
Interest income......................................        --      3,664        446
</Table>

     The Partnership reimburses the Company for salaries, benefits and other
incurred expenses. Benefits include pension, thrift plan, and other
postretirement benefits. Operating expenses charged by the Company in 2001, 2000
and 1999 were $13,671,000, $21,147,000 and $25,348,000, respectively.

     The Company accounts for pension benefits on an accrual basis. Effective
with the merger of The Coastal Corporation and El Paso Corporation in 2001, the
former pension plan was merged into the El Paso cash balance pension plan. The
annual net pension credit was $8,500,000, $5,000,000 and $4,300,000, in 2001,
2000 and 1999, respectively.

     In 1999, the Company amended its existing pension plan to offer a voluntary
Early Retirement Incentive Program (ERIP) to employees who were at least 55
years of age with at least 5 years of service. Cost related to the ERIP of
approximately $4,600,000 were recorded in 1999.

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

                                        94
<PAGE>
                GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

on matching employee contributions, amounted to $832,000, $980,000 and
$1,022,000 in 2001, 2000 and 1999, respectively.

     The Company accounts for other post-retirement benefits on an accrual
basis. The annual expense was $215,000 for 2001 and $556,000 for both 2000 and
1999. In addition, curtailment costs of approximately $695,000 were recorded in
2001 related to the conversion to the El Paso Corporation benefit plans which
changed future benefits for eligible employees.

4.  REGULATORY MATTERS

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

5.  DEBT

<Table>
<Caption>
                                                                2001       2000
                                                              --------   --------
                                                                (IN THOUSANDS)
<S>                                                           <C>        <C>
Senior Notes, unsecured, interest due semiannually,
  principal due as follows:
  9.81% series, due 2002 to 2003............................  $ 12,750   $ 25,250
  9.35% series, due 2002 to 2005............................    56,000     70,000
  8.74% series, due 2002 to 2011............................   100,000    100,000
  9.09% series, due 2012 to 2021............................   100,000    100,000
  6.73% series, due 2009 to 2018............................    90,000     90,000
  6.95% series, due 2019 to 2028............................   110,000    110,000
  8.08% series, due 2021 to 2030............................   100,000    100,000
                                                              --------   --------
                                                               568,750    595,250
Less current maturities.....................................    36,500     19,500
                                                              --------   --------
Total long term debt less current maturities................  $532,250   $575,750
                                                              ========   ========
</Table>

     The aggregate estimated fair value of long term debt was $607,000,000 and
$615,000,000 for 2001 and 2000, respectively. The fair value is determined using
discounted cash flows based on the Partnership's estimated current interest
rates for similar debt.

     The aggregate annual required repayments of Senior Notes for each of the
five years 2002 through 2006 are $36,500,000, $24,250,000, $24,000,000,
$24,000,000 and $17,000,000, respectively.

     Under the most restrictive covenants in the Senior Note Agreements,
approximately $306,000,000 of partners' capital is restricted as to
distributions as of December 31, 2001.

                                        95
<PAGE>
                GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

6.  INCOME TAXES PAYABLE BY PARTNERS

     Income tax expense for the years ended December 31, 2001, 2000 and 1999
consists of:

<Table>
<Caption>
                                                           2001      2000      1999
                                                          -------   -------   -------
                                                                (IN THOUSANDS)
<S>                                                       <C>       <C>       <C>
Current
  Federal...............................................  $22,366   $23,496   $26,893
  State and local.......................................    1,012     1,052     1,568
                                                          -------   -------   -------
                                                           23,378    24,548    28,461
                                                          -------   -------   -------
Deferred
  Federal...............................................   15,835    14,306    10,884
  State and local.......................................      737       664       687
                                                          -------   -------   -------
                                                           16,572    14,970    11,571
                                                          -------   -------   -------
                                                          $39,950   $39,518   $40,032
                                                          =======   =======   =======
</Table>

     Income tax expense differs from the statutory rate of 35% due to the
amortization of excess deferred taxes along with the effects of state and local
taxes. The Partnership is required to amortize excess deferred taxes which had
previously been accumulated at tax rates in excess of current statutory rates.
Such amortization reduced income tax expense by $900,000 for 2001, 2000 and
1999. As of December 31, 2001, the remaining unamortized balance is $2,375,000.

     Amounts equivalent to deferred income taxes include the effects of
temporary differences associated with excess tax depreciation on utility plant
and state taxes. As of December 31, 2001 and 2000, no valuation allowance is
required. The deferred tax assets and deferred tax liabilities as of December
31, 2001 and 2000 are as follows:

<Table>
<Caption>
                                                                2001        2000
                                                              ---------   ---------
                                                                 (IN THOUSANDS)
<S>                                                           <C>         <C>
Deferred tax assets.........................................  $   4,868   $   3,951
Deferred tax liabilities....................................   (210,925)   (197,090)
                                                              ---------   ---------
Net deferred tax liability..................................  $(206,057)  $(193,139)
                                                              =========   =========
</Table>

7.  CONTINGENCIES

     Great Lakes has pending refund claims related to use taxes paid to the
State of Minnesota for years 1994 to 2000. No amounts have been recorded in the
financial statements related to the ultimate outcome of this contingency.

                                        96
<PAGE>

                              EL PASO CGP COMPANY

                                  EXHIBIT LIST

                               DECEMBER 31, 2001

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

<Table>
<Caption>
EXHIBIT NO.                                      DESCRIPTION
-----------                                      -----------
<C>                      <S>
            3.A          -- Amended and Restated Certificate of Incorporation dated
                            January 31, 2001 (Exhibit 3.A to our 2000 Form 10-K).
            3.B          -- By-Laws dated January 29, 2001 (Exhibit 3.B to 2000 Form
                            10-K).
           10.A          -- $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.G to our 2000 Form 10-K).
           10.B          -- Joinder Agreement dated February 5, 2001 made by El Paso
                            CGP Company to the $1,000,000,000 3-Year Revolving Credit
                            and CAF Advance Facility Agreement 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, as Administrative Agent and CAF
                            Advance Agent, Citibank, N.A. and ABN Amro, N.V. as
                            Co-Documentation Agents, and Bank of America, N.A. as
                            syndication agent for the Lenders (Exhibit 10.H to our
                            2000 Form 10-K).
          *18            -- Letter regarding Change in Accounting Principle
          *99.1          -- Report of Independent Accountants, PricewaterhouseCoopers
                            LLP
          *99.2          -- Independent Auditors' Report, Deloitte & Touche LLP
</Table>

     (B) REPORTS ON FORM 8-K

        None.

                                        97
<PAGE>

                                   SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, as amended, El Paso CGP Company has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly authorized
on the 28th day of March 2002.

                                        EL PASO CGP COMPANY
                                        (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 CGP Company and in the capacities and on the dates indicated:

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

              By: /s/ WILLIAM A. WISE                Chairman of the Board,             March 28, 2002
  ----------------------------------------------       President and Chief Executive
                 (William A. Wise)                     Officer and Director
                                                       (Principal Executive Officer)

              By: /s/ H. BRENT AUSTIN                Executive Vice President and       March 28, 2002
  ----------------------------------------------       Chief Financial Officer and
                 (H. Brent Austin)                     Director (Principal Financial
                                                       Officer)

             By: /s/ JEFFREY I. BEASON               Senior Vice President and          March 28, 2002
  ----------------------------------------------       Controller (Principal
                (Jeffrey I. Beason)                    Accounting Officer)
</Table>

                                        98
<PAGE>

                                 EXHIBIT INDEX

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

<Table>
<Caption>
EXHIBIT NO.                                      DESCRIPTION
-----------                                      -----------
<C>                      <S>
            3.A          -- Amended and Restated Certificate of Incorporation dated
                            January 31, 2001 (Exhibit 3.A to our 2000 Form 10-K).
            3.B          -- By-Laws dated January 29, 2001 (Exhibit 3.B to 2000 Form
                            10-K).
           10.A          -- $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.G to our 2000 Form 10-K).
           10.B          -- Joinder Agreement dated February 5, 2001 made by El Paso
                            CGP Company to the $1,000,000,000 3-Year Revolving Credit
                            and CAF Advance Facility Agreement 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, as Administrative Agent and CAF
                            Advance Agent, Citibank, N.A. and ABN Amro, N.V. as
                            Co-Documentation Agents, and Bank of America, N.A. as
                            syndication agent for the Lenders (Exhibit 10.H to our
                            2000 Form 10-K).
          *18            -- Letter regarding Change in Accounting Principle
          *99.1          -- Report of Independent Accountants, PricewaterhouseCoopers
                            LLP
          *99.2          -- Independent Auditors' Report, Deloitte & Touche LLP
</Table>