<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 1-4874

                        COLORADO INTERSTATE GAS COMPANY
             (Exact name of registrant as specified in its charter)

<Table>
<S>                                             <C>
                  DELAWARE                                       84-0173305
       (State or other jurisdiction of                        (I.R.S. Employer
       incorporation or organization)                        Identification No.)

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

      REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE:  (713) 420-2600

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

<Table>
<Caption>
       TITLE OF EACH CLASS                                    NAME OF EACH EXCHANGE ON WHICH REGISTERED
       -------------------                                    -----------------------------------------
<C>                               <C> <S>                     <C>
 10% Senior Debentures, due 2005
                                      .......................         New York Stock Exchange

6.85% Senior Debentures, due 2037
</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 SHARE OUTSTANDING AT EACH OF THE REGISTRANT'S
CLASSES OF COMMON STOCK, AS OF THE LATEST PRACTICABLE DATE.

     Common Stock, no par value. Shares outstanding on March 28, 2002: 10

     COLORADO INTERSTATE GAS 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>

                        COLORADO INTERSTATE GAS COMPANY

                               TABLE OF CONTENTS

<Table>
<Caption>
                                     CAPTION                              PAGE
                                     -------                              ----
<S>        <C>                                                            <C>
                                    PART I
Item 1.    Business....................................................     1
Item 2.    Properties..................................................     7
Item 3.    Legal Proceedings...........................................     7
Item 4.    Submission of Matters to a Vote of Security Holders.........     *

                                   PART II
Item 5.    Market for the Registrant's Common Equity and Related
           Stockholder Matters.........................................     7
Item 6.    Selected Financial Data.....................................     *
Item 7.    Management's Discussion and Analysis of Financial Condition
           and Results of   Operations.................................     8
           Cautionary Statement for purposes of the "Safe Harbor"
           Provisions of the Private   Securities Litigation Reform Act
           of 1995.....................................................    10
Item 7A.   Quantitative and Qualitative Disclosures About Market
           Risk........................................................    11
Item 8.    Financial Statements and Supplementary Data.................    12
Item 9.    Changes in and Disagreements with Accountants on Accounting
           and Financial   Disclosure..................................    36

                                   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.........................................................    36
           Signatures..................................................    38
</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
BBtu     = billion British thermal units
Bbl      = barrels
Bcf      = billion cubic feet
MBbls    = thousand barrels
Mcf      = thousand cubic feet
MMcf     = million cubic feet
MMcfe    = million 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 "us", "we", "our", or "ours", we are describing Colorado
Interstate Gas Company and/or our subsidiaries.

                                       (i)
<PAGE>

                                     PART I

ITEM 1. BUSINESS

                                    GENERAL

     We are a Delaware corporation incorporated in 1927. In January 2001, we
became a wholly owned subsidiary of El Paso Corporation through the merger of a
wholly owned El Paso subsidiary with The Coastal Corporation (Coastal). On June
29, 2001, all of our outstanding common stock was contributed from our former
parent company, El Paso CNG Company (formerly Coastal Natural Gas Company) to
Noric Holdings III L.L.C. (Noric III), a wholly owned subsidiary of El Paso. We
own and operate an interstate natural gas pipeline system, natural gas
processing facilities and gathering systems. We also have natural gas and oil
exploration and production operations.

                                    SEGMENTS

     Our operations are segregated into two primary business segments: Pipeline
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 marketing strategies. For information relating
to operating revenues, operating income, earnings before interest and income
taxes (EBIT) and identifiable assets by segment, you should see Part II, Item 8,
Financial Statements and Supplementary Data, Note 9, which is incorporated
herein by reference.

                                PIPELINE SEGMENT

     Our Pipeline segment provides natural gas transmission services and
consists of approximately 4,600 miles of pipeline with a design capacity of
2,928 MMcf/d. During 2001, 2000 and 1999, average throughput was 1,448 BBtu/d,
1,383 BBtu/d and 1,301 BBtu/d. Our system extends from most production areas in
the 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. We have
approximately 29 Bcf of underground working gas storage capacity along our
system.

     In addition to our existing system, the Federal Energy Regulatory
Commission (FERC) has approved the Front Range Expansion project. This project
will install compression and pipeline looping to increase deliverability along
the Colorado Front Range market area. 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.
This project will add approximately 283 MMcf/d to our capacity and is
anticipated to be completed in December 2002.

     Our Pipeline segment also produces and sells natural gas and oil under
contracts covering producing fields in the Panhandle region in Texas, Oklahoma
and Kansas. See a discussion of our reserves on these fields under Other
Operations below. The natural gas we produce is primarily sold to Pioneer
Natural Resources USA, Inc., or sold at the wellhead and delivered to our
interstate natural gas pipeline system. The crude oil and condensate produced
are sold at the wellhead to oil purchasing companies at prevailing market
prices. The production of natural gas and oil is subject to regulation in the
states in which we operate. For a further discussion of our Pioneer contract,
see Part II, Item 8, Financial Statements and Supplementary Data, Note 7.

                             REGULATORY ENVIRONMENT

     Our interstate system is regulated by the FERC under the Natural Gas Act of
1938 and the Natural Gas Policy Act of 1978. This system operates under a
separate FERC approved tariff that establishes rates, terms and conditions under
which it 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;

                                        1
<PAGE>

     - 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 tariff was established through filings with the FERC, and affects our
operations and our ability to recover fees for the services we provide.
Generally, changes to these fees or terms of service can only be implemented
upon approval by the FERC.

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

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

     For a discussion of significant rates and regulatory matters, see Part II,
Item 8, Financial Statements and Supplementary Data, Note 7.

                            MARKETS AND COMPETITION

     Our interstate transmission system faces varying degrees of competition
from other pipelines, as well as alternative energy sources. 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.

     We have approximately 165 firm and interruptible customers, including
natural gas producers, marketers, end users and other natural gas transmission,
distribution and electric generation companies. We have approximately 160 firm
transportation contracts, with remaining terms that extend from 2 months to 23
years, and with an average remaining term of 7 years. Substantially all of our
firm capacity is fully subscribed. The significant customer we served during
2001 was Public Service Company of Colorado with capacity of 1,231 BBtu/d under
contract until 2007.

     We serve two major markets, our "on-system" market, consisting of utilities
and other customers located along the front range of the Rocky Mountains in
Colorado and Wyoming, and our "off-system" market, consisting of the
transportation of Rocky Mountain production from multiple supply basins to
interconnections with other pipelines bound for the Midwest, the Southwest,
California and the Pacific Northwest. We face different types of competition in
both markets. In the on-system market, competition comes from local supply in
the Denver-Julesburg basin, from an intrastate pipeline directly serving Denver
and from off-system shippers who can deliver their gas in that market,
supplanting our transportation for on-system customers. In our "off-system"
market, we face competition in our supply areas from competitors who can ship
natural gas to the Midwest, California, the Southwest and Pacific Northwest.

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

                                        2
<PAGE>

                             FIELD SERVICES SEGMENT

     Our Field Services segment provides midstream services in the Rocky
Mountain and Mid-Continent regions, including natural gas gathering, treating
and processing. Our natural gas gathering and processing facilities are located
throughout the production areas adjacent to our transmission system. We own and
operate various gathering lines, field compressors and gathering systems which
gathered 421 MMcf/d and 510 MMcf/d for the years ended December 31, 2001 and
2000.

     We own and operate one natural gas processing plant which has operating
capacity of 15 MMcf/d . We also have processing arrangements on three additional
plants in which we pay a fee to the plant owners to have natural gas processed
at these locations. The products that these plants recover include ethane,
propane, isobutane, normal butane, natural gas and helium.

                             REGULATORY ENVIRONMENT

     Our Field Services operations are subject to the Natural Gas Pipeline
Safety Act of 1968, the Hazardous Liquid Pipeline Safety Act and the National
Environmental Policy Act. 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

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

                                OTHER OPERATIONS

     Our Other Operations include natural gas and oil development and production
in the U.S.

  Natural Gas and Oil Reserves

     The following table details our proved reserves for both our Pipeline
segment and other production activities at December 31, 2001. All of our
production activities are in the U.S.

<Table>
<Caption>
                                                              NET PROVED RESERVES(1)
                                                          ------------------------------
                                                          NATURAL
                                                            GAS     LIQUIDS(2)    TOTAL
                                                          -------   ----------   -------
                                                          (MMCF)     (MBBLS)     (MMCFE)
<S>                                                       <C>       <C>          <C>
Pipeline segment
     Producing..........................................  182,857        97      183,439
                                                          -------      ----      -------
          Total proved..................................  182,857        97      183,439
                                                          =======      ====      =======
Other
     Producing..........................................    2,130         7        2,172
     Non-producing......................................      107         1          112
     Undeveloped........................................    2,326        29        2,502
                                                          -------      ----      -------
          Total proved..................................    4,563        37        4,786
                                                          =======      ====      =======
</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.

     For a further discussion of our reserves, see Part II, Item 8, Financial
Statements and Supplementary Data, Note 14.

                                        3
<PAGE>

  Wells and Acreage

     The following table details our gross and net interest in developed and
undeveloped acreage at December 31, 2001:

<Table>
<Caption>
                                 DEVELOPED           UNDEVELOPED            TOTAL
                             ------------------   -----------------   -----------------
                              GROSS     NET(1)     GROSS    NET(1)     GROSS    NET(1)
                             --------   -------   -------   -------   -------   -------
<S>                          <C>        <C>       <C>       <C>       <C>       <C>
Pipeline Segment...........   262,474   259,276        --        --   262,474   259,276
Other......................     8,247     4,109    10,171     8,949    18,418    13,058
                             --------   -------   -------   -------   -------   -------
                              270,721   263,385    10,171     8,949   280,892   272,334
                             ========   =======   =======   =======   =======   =======
</Table>

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

(1) Net indicates our net ownership in this acreage.

     Our net developed acreage is concentrated primarily in Texas (93 percent)
and Oklahoma (7 percent). Approximately 1 percent and 87 percent of our total
net undeveloped acreage is under leases that have minimum remaining primary
terms expiring in 2002 and 2004.

     The following table details our domestic productive wells at December 31,
2001:

<Table>
<Caption>
                                                              GROSS   NET
                                                              -----   ---
<S>                                                           <C>     <C>
Pipeline Segment
  Natural Gas...............................................   793    788
  Oil.......................................................     9      8
                                                               ---    ---
          Total.............................................   802    796
                                                               ---    ---
Other
  Natural Gas...............................................    21      6
                                                               ---    ---
          Total.............................................    21      6
                                                               ---    ---
               Total........................................   823    802
                                                               ===    ===
</Table>

     The following table details our development wells drilled during the years
1999 through 2001:

<Table>
<Caption>
                                                    2001           2000          1999
                                                 -----------   ------------   -----------
                                                 GROSS   NET   GROSS   NET    GROSS   NET
                                                 -----   ---   -----   ----   -----   ---
<S>                                              <C>     <C>   <C>     <C>    <C>     <C>

Pipeline Segment
  Productive...................................    5      5       7      1      22    13
                                                  --     --    ----    ----   ----    --
          Total................................    5      5       7      1      22    13
                                                  --     --    ----    ----   ----    --
Other
  Productive...................................   --     --      --     --      11     7
                                                  --     --    ----    ----   ----    --
          Total................................   --     --      --     --      11     7
                                                  --     --    ----    ----   ----    --
            Total..............................    5      5       7      1      33    20
                                                  ==     ==    ====    ====   ====    ==
</Table>

     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.

                                        4
<PAGE>

  Net Production, Unit Prices and Production Costs

     The following table details our 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>
Pipeline Segment
  Natural Gas (MMcf).......................................  30,393   33,433   35,634
  Oil, Condensate and Liquids (MBbls)......................      16       25       24
Average Sales Price(1)
  Natural Gas ($/Mcf)......................................  $ 3.00   $ 2.06   $ 1.38
  Oil, Condensate and Liquids ($/Bbl)......................  $22.56   $27.79   $15.03
Other
  Natural Gas (MMcf).......................................   1,081    3,663    5,495
  Oil, Condensate and Liquids (MBbls)......................      13      160       80
Average Sales Price(1)
  Natural Gas ($/Mcf)......................................  $ 4.93   $ 3.80   $ 1.93
  Oil, Condensate and Liquids ($/Bbl)......................  $20.74   $16.12   $15.30
Average Production Cost ($/Mcfe)(2)........................  $ 0.59   $ 0.38   $ 0.59
</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.

                      REGULATORY AND OPERATING ENVIRONMENT

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

     Our production 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. These domestic laws and regulations
relating to the protection of the environment affect our natural gas and oil
operations through their effect on the construction and operation of facilities,
drilling operations, production or the delay or prevention of future offshore
lease sales. We believe that our operations are in compliance with the
applicable requirements. In addition, we maintain insurance for sudden and
accidental spills and oil pollution liability.

     Our business has operating risks normally associated with drilling and
production of natural gas and oil, including blowouts, cratering, pollution and
fires, each of which could result in damage to life or property. Customary with
industry practices, we maintain insurance coverage with respect to potential
losses resulting from these operating hazards. However, insurance is not
available to us 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. Our 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

                                        5
<PAGE>

price, contract terms and quality of service. To some degree, we mitigate our
price risk by hedging the cash flows from our natural gas and oil producing
activities. 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.

                                 ENVIRONMENTAL

     A description of our environmental activities is included in Part II, Item
8, Financial Statements and Supplementary Data, Note 7, and is incorporated
herein by reference.

                                   EMPLOYEES

     As of March 28, 2002, we had approximately 250 full-time employees, none of
whom are subject to collective bargaining agreements.

                                        6
<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 these
properties in our businesses. We believe that our properties are adequate and
suitable for the conduct of our business in the future.

ITEM 3. LEGAL PROCEEDINGS

     A description of our legal proceedings is included in Part II, Item 8,
Financial Statements and Supplementary Data, Note 7, and is incorporated herein
by reference.

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

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

                                    PART II

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

     On January 29, 2001, El Paso CGP Company (formerly The Coastal Corporation)
became a wholly owned subsidiary of El Paso. On June 29, 2001, all of our common
stock was contributed from El Paso CNG, a subsidiary of El Paso, to Noric III.
Accordingly, there is no public trading market for our common stock.

     We pay dividends on our common stock from time to time from legally
available funds that have been approved for payment by our Board of Directors.
We paid cash dividends of $120 million and $39 million to our parent in 2001 and
2000.

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.

                                        7
<PAGE>

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

     The information required by this Item is presented in a reduced disclosure
format pursuant to 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.

                                SEGMENT RESULTS

     Our business activities are segregated into two segments: Pipeline and
Field Services. These segments are strategic business units that offer a variety
of different energy products and services, and each requires different
technology and marketing strategies. Our historical segments (natural gas
systems and exploration and production) 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. In
addition, during 2001, Field Services became a separate segment reflecting the
fact that it is managed separately from our Pipeline segment. 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
place 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 products sold) provides a more accurate
and meaningful basis for analyzing operating results for our Field Services
segment. For a further discussion of our individual segments, see Item 8,
Financial Statements and Supplementary Data, Note 9. The following table
presents earnings before interest and income taxes (EBIT) by segment and in
total for each of the years ended December 31:

<Table>
<Caption>
                                                              2001    2000
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
  Pipeline..................................................  $126    $159
  Field Services............................................    22      14
                                                              ----    ----
       Segment total........................................   148     173
  Corporate and other, net..................................     5       8
                                                              ----    ----
       Consolidated EBIT....................................  $153    $181
                                                              ====    ====
</Table>

PIPELINE

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

<Table>
<Caption>
                                                                2001        2000
                                                              ---------   ---------
                                                              (IN MILLIONS, EXCEPT
                                                                 VOLUME AMOUNTS)
<S>                                                           <C>         <C>
Operating revenues..........................................   $  367      $  338
Operating expenses..........................................     (244)       (183)
Other income................................................        3           4
                                                               ------      ------
     EBIT...................................................   $  126      $  159
                                                               ======      ======
Throughput volumes (BBtu/d).................................    1,448       1,383
                                                               ======      ======
</Table>

                                        8
<PAGE>

     Included in our results of operations for the year ended December 31, 2001,
are merger-related costs of $31 million associated with El Paso Corporation's
merger with The Coastal Corporation in January 2001. These costs include
employee severance, retention and transition costs and costs for post-retirement
benefits settled and curtailed under existing benefit plans.

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

     Operating revenues for the year ended December 31, 2001, were $29 million
higher than the same period in 2000. The increase was due to higher
transportation and storage revenues as a result of completed system expansions
and new contracts during 2001, higher realized prices on company owned
production and increased fuel recoveries due to higher natural gas prices and
increased fuel efficiencies. The increase was partially offset by the favorable
resolution of natural gas price-related contingencies in 2000.

     Operating expenses for the year ended December 31, 2001, were $61 million
higher than the same period in 2000. The increase was a result of merger-related
costs arising from employee benefits and severance charges and other merger
charges related to El Paso's merger with Coastal, increased corporate
allocations and higher fuel costs resulting from higher natural gas prices.

FIELD SERVICES

     The Field Services segment provides midstream services in the Rockies and
Mid-Continent regions, including gathering and treating of natural gas and the
processing of natural gas. The gathering and treating operations earn margins
substantially from fixed-fee-based services; however, some of these operations
earn margins from market-based rates. Processing operations earn a margin based
on make-whole contracts which allow us to retain the extracted liquid products
and return to the producer a Btu equivalent amount of natural gas. Under
market-based rates 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 these results are as
follows for each of the years ended December 31:

<Table>
<Caption>
                                                              2001     2000
                                                              -----    -----
                                                              (IN MILLIONS)
<S>                                                           <C>      <C>
Gathering, treating and processing gross margin.............   $31     $ 30
Operating expenses..........................................    (9)     (16)
                                                               ---     ----
     EBIT...................................................   $22     $ 14
                                                               ===     ====
</Table>

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

     Total gross margin for the year ended December 31, 2001, was $1 million
higher than the same period in 2000. The increase was a result of higher volumes
in 2001 due to the transfer of natural gas processing contracts from an
affiliate. This transfer was due to the re-alignment of our activities as a
result of our parent's merger with El Paso. The increase was partially offset by
lower gathering and treating volumes due to a natural decline in natural gas
reserves.

     Operating expenses for the year ended December 31, 2001, were $7 million
lower than the same period in 2000 due to lower general and administrative
expenses.

AFFILIATED INTEREST INCOME, NET

     Affiliated interest income, net, for the year ended December 31, 2001, was
$11 million lower than the same period in 2000 primarily due to lower interest
rates on advances under our cash management program with El Paso.

                                        9
<PAGE>

INCOME TAXES

     The effective income tax rate for the years ended December 31, 2001, and
2000 was 34 percent and 36 percent. The effective tax rates were different than
the statutory rate of 35 percent primarily due to state income taxes and
dividends from affiliated companies. For a reconciliation of statutory rate to
effective tax rate, see Item 8, Financial Statements and Supplementary Data,
Note 3.

COMMITMENTS AND CONTINGENCIES

     For a discussion of our commitments and contingencies, see Item 8,
Financial Statements and Supplementary Data, Note 7, which 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 the
differences between assumed facts or bases and actual results can be material,
depending upon the circumstances. Where, in any forward-looking statement, we or
our management express an expectation or belief as to future results, that
expectation or belief is expressed in good faith and is believed to have a
reasonable basis. We cannot assure you, however, that the statement of
expectation or belief will result or be achieved or accomplished. The words
"believe," "expect," "estimate," "anticipate" and similar expressions will
generally identify forward-looking statements. Our forward-looking statements,
whether written or oral, are expressly qualified by these cautionary statements
and any other cautionary statements that may accompany those statements. In
addition, we disclaim any obligation to update any forward-looking statements to
reflect events or circumstances after the date of this report.

                                        10
<PAGE>

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

INTEREST RATE RISK

     Our primary market risk is exposure to changing interest rates. The table
below shows the carrying value and related weighted average interest rates of
our interest bearing securities, by expected maturity dates. As of December 31,
2001, the fair value of our long-term debt has been estimated based on quoted
market prices for the same or similar issues.

<Table>
<Caption>
                                                    DECEMBER 31, 2001
                              -------------------------------------------------------------     DECEMBER 31,
                                  EXPECTED FISCAL YEAR OF MATURITY OF CARRYING AMOUNTS              2000
                              -------------------------------------------------------------   ----------------
                                                                                      FAIR    CARRYING   FAIR
                              2002   2003   2004   2005   2006   THEREAFTER   TOTAL   VALUE   AMOUNTS    VALUE
                              ----   ----   ----   ----   ----   ----------   -----   -----   --------   -----
                                                  (DOLLARS IN MILLIONS)
<S>                           <C>    <C>    <C>    <C>    <C>    <C>          <C>     <C>     <C>        <C>
LIABILITIES:
  Long-term debt, including
     current
     portion -- fixed rate..                       $180             $100      $280    $306      $280     $299
       Average interest
          rate..............                         10%            6.85%
</Table>

NON-TRADING COMMODITY PRICE RISK

     We have entered into hedging transactions to manage commodity price risk
related to a portion of our natural gas production. The table below presents the
hypothetical changes in fair values arising from immediate selected potential
changes in the quoted market prices of derivative commodity instruments
outstanding at December 31, 2001 and 2000. Gain or loss on these derivative
commodity instruments would be offset by a corresponding gain or loss on the
hedged commodity, which are not included in the table.

<Table>
<Caption>
                                                       YEAR END      10% INCREASE          10% DECREASE
                                                       --------   ------------------   ---------------------
                                                         FAIR     FAIR    INCREASE/    FAIR       INCREASE/
                                                        VALUE     VALUE   (DECREASE)   VALUE      (DECREASE)
                                                       --------   -----   ----------   -----      ----------
                                                                           (IN MILLIONS)
<S>                                                    <C>        <C>     <C>          <C>        <C>
Impact of changes in commodity prices on derivative
  commodity instruments:
  2001...............................................    $  3     $  2       $ (1)     $  4          $  1
  2000...............................................    $ (2)    $ (3)      $ (1)     $ (1)         $  1
</Table>

                                        11
<PAGE>

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                        COLORADO INTERSTATE GAS COMPANY

                       CONSOLIDATED STATEMENTS OF INCOME
                                 (IN MILLIONS)

<Table>
<Caption>
                                                              YEAR ENDED DECEMBER 31,
                                                              ------------------------
                                                               2001     2000     1999
                                                              ------   ------   ------
<S>                                                           <C>      <C>      <C>
Operating revenues..........................................   $497     $388     $311
                                                               ----     ----     ----
Operating expenses
  Operation and maintenance.................................    262      157      120
  Merger-related costs......................................     31       --       --
  Depreciation, depletion and amortization..................     37       35       29
  Taxes, other than income taxes............................     17       18       16
                                                               ----     ----     ----
                                                                347      210      165
                                                               ----     ----     ----
Operating income............................................    150      178      146
                                                               ----     ----     ----
Other income
  Affiliated dividend income................................      3       --       --
  Other, net................................................     --        3        1
                                                               ----     ----     ----
                                                                  3        3        1
                                                               ----     ----     ----
Income before interest, income taxes and other charges......    153      181      147
                                                               ----     ----     ----
Non-affiliated interest and debt expense....................     23       24       25
Affiliated interest income, net.............................    (11)     (22)     (15)
Income taxes................................................     48       65       50
                                                               ----     ----     ----
                                                                 60       67       60
                                                               ----     ----     ----
Net income..................................................   $ 93     $114     $ 87
Other comprehensive income..................................      3       --       --
                                                               ----     ----     ----
Comprehensive income........................................   $ 96     $114     $ 87
                                                               ====     ====     ====
</Table>

                            See accompanying notes.

                                        12
<PAGE>

                        COLORADO INTERSTATE GAS COMPANY

                          CONSOLIDATED BALANCE SHEETS
                      (IN MILLIONS, EXCEPT SHARE AMOUNTS)

<Table>
<Caption>
                                                               DECEMBER 31,
                                                              ---------------
                                                               2001     2000
                                                              ------   ------
<S>                                                           <C>      <C>
                                   ASSETS

Current assets
  Cash and cash equivalents.................................  $    1   $    1
  Accounts and notes receivable, net of allowance of less
     than $1 for 2001 and 2000
     Customer...............................................      50       61
     Affiliates.............................................     280      349
     Other..................................................      10        1
  Materials and supplies....................................       5        7
  Deferred income taxes.....................................      11       18
  Other.....................................................       9       --
                                                              ------   ------
          Total current assets..............................     366      437
                                                              ------   ------
Property, plant and equipment, at cost
  Pipeline..................................................   1,321    1,151
  Gathering and processing systems..........................     151      148
  Natural gas and oil properties, at full cost..............     164      100
                                                              ------   ------
                                                               1,636    1,399
  Less accumulated depreciation, depletion and
     amortization...........................................     818      732
                                                              ------   ------
          Total property, plant and equipment, net..........     818      667
                                                              ------   ------
Investments in unconsolidated affiliates....................      29       62
                                                              ------   ------
Other.......................................................       6       23
                                                              ------   ------
          Total assets......................................  $1,219   $1,189
                                                              ======   ======

                    LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities
  Accounts and notes payable
     Trade..................................................  $   32   $   19
     Affiliates.............................................      10        9
     Other..................................................      28       32
  Taxes payable.............................................      41       15
  Other.....................................................      42       44
                                                              ------   ------
          Total current liabilities.........................     153      119
                                                              ------   ------
Long-term debt..............................................     280      280
                                                              ------   ------
Deferred income taxes.......................................     121      119
                                                              ------   ------
Other.......................................................      26       10
                                                              ------   ------

Commitments and contingencies
Minority interest...........................................       3        2
                                                              ------   ------
Stockholder's equity
  Common stock, no par value; authorized 10,000 shares;
     issued and outstanding 10 shares at stated value.......      28       28
  Additional paid-in capital................................      20       19
  Retained earnings.........................................     585      612
  Accumulated other comprehensive income....................       3       --
                                                              ------   ------
          Total stockholder's equity........................     636      659
                                                              ------   ------
          Total liabilities and stockholder's equity........  $1,219   $1,189
                                                              ======   ======
</Table>

                            See accompanying notes.
                                        13
<PAGE>

                        COLORADO INTERSTATE GAS 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................................................   $  93     $114     $ 87
  Adjustments to reconcile net income to net cash from
     operating activities
     Depreciation, depletion and amortization...............      37       35       29
     Deferred income tax expense............................       9       23        7
     Non-cash portion of merger-related costs...............      17       --       --
     Working capital changes, net of non-cash transactions
       Accounts receivable..................................       1      (13)      (7)
       Accounts payable.....................................     (35)     (24)      (4)
       Accounts payable/receivable with affiliates..........     (28)      11      (18)
       Taxes payable........................................      26       (7)      --
     Other working capital changes..........................      41       (3)      --
     Non-working capital changes and other..................      (1)      --       --
                                                               -----     ----     ----
          Net cash provided by operating activities.........     160      136       94
                                                               -----     ----     ----
Cash flows from investing activities
  Additions to property, plant and equipment................    (175)     (63)     (46)
  Net proceeds from the sale of assets......................       3       --       11
  Return of capital from investments........................      33       --       --
  Investments in unconsolidated affiliates..................      --        2       (4)
  Net change in affiliated advances receivable..............      99      (34)     (54)
                                                               -----     ----     ----
          Net cash used in investing activities.............     (40)     (95)     (93)
                                                               -----     ----     ----
Cash flows from financing activities
  Net change in note payable to affiliate...................      --       (2)      --
  Dividends paid............................................    (120)     (39)      --
                                                               -----     ----     ----
          Net cash used in financing activities.............    (120)     (41)      --
                                                               -----     ----     ----
Increase in cash and cash equivalents.......................      --       --        1
Cash and cash equivalents
  Beginning of period.......................................       1        1       --
                                                               -----     ----     ----
  End of period.............................................   $   1     $  1     $  1
                                                               =====     ====     ====
</Table>

                            See accompanying notes.

                                        14
<PAGE>

                        COLORADO INTERSTATE GAS COMPANY

                CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY
                      (IN MILLIONS, EXCEPT SHARE AMOUNTS)

<Table>
<Caption>
                                                                            ACCUMULATED
                                  COMMON STOCK     ADDITIONAL                  OTHER           TOTAL
                                 ---------------    PAID-IN     RETAINED   COMPREHENSIVE   STOCKHOLDER'S
                                 SHARES   AMOUNT    CAPITAL     EARNINGS      INCOME          EQUITY
                                 ------   ------   ----------   --------   -------------   -------------
<S>                              <C>      <C>      <C>          <C>        <C>             <C>
January 1, 1999................  10,000    $28        $19        $ 450          --             $ 497
  Net income...................                                     87                            87
                                 ------    ---        ---        -----          --             -----
December 31, 1999..............  10,000     28         19          537          --               584
  Net income...................                                    114                           114
  Cash dividend................                                    (39)                          (39)
                                 ------    ---        ---        -----          --             -----
December 31, 2000..............  10,000     28         19          612          --               659
  Net income...................                                     93                            93
  Allocated tax benefit of El
     Paso equity plans.........                         1                                          1
  Other comprehensive income...                                                  3                 3
  Cash dividend................                                   (120)                         (120)
                                 ------    ---        ---        -----          --             -----
December 31, 2001..............  10,000    $28        $20        $ 585          $3             $ 636
                                 ======    ===        ===        =====          ==             =====
</Table>

                            See accompanying notes.

                                        15
<PAGE>

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

  Materials and Supplies

     We value materials and supplies at the lower of cost or market value with
cost determined using the average cost method.

  Natural Gas Imbalances

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

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

                                        16
<PAGE>

  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, 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 a 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 a ceiling test calculation each quarter. Although we had no write-downs
in the periods presented, any required write-downs would be included in our
income statements 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.

     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.

  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 all direct and indirect costs of the project, including interest
costs on related debt. 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       2-53        2% to 27%
Gathering and processing systems.......................  Straight-line       1-40        3% to 20%
Transportation equipment...............................  Straight-line       1-5        20% to 33%
Buildings and improvements.............................  Straight-line       1-40         3% to 7%
Office and miscellaneous equipment.....................  Straight-line       1-10       10% to 33%
</Table>

     When we retire properties, we reduce property, plant and equipment for its
original cost, less accumulated depreciation, and salvage. Any remaining amount
is charged to income.

     At December 31, 2001 and 2000, we had approximately $25 million and $33
million of construction work in progress included in our property, plant and
equipment.

  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.

     On January 1, 2002, we adopted the provision of SFAS No. 144, Accounting
for the Impairment or Disposal of Long-Lived Assets, which will impact how we
account for asset impairments and the accounting for discontinued operations in
the future.

                                        17
<PAGE>

  Revenue Recognition

     We recognize revenues from natural gas transportation and storage service
in the period the service is provided. Our other business activities 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 the impact on our revenues from our hedging
activities.

  Environmental Costs and Other Contingencies

     We expense or capitalize expenditures for ongoing compliance with
environmental regulations that relate to past or current operations as
appropriate. We expense amounts for clean up of existing environmental
contamination caused by past operations which do not benefit future periods by
preventing or eliminating future contamination. We record liabilities when our
environmental assessments indicate that remediation efforts are probable, and
the costs can be reasonably estimated. Estimates of our liabilities are based on
currently available facts, existing technology and presently enacted laws and
regulations taking into consideration the likely effects of inflation and other
societal and economic factors, and include estimates of associated legal costs.
These amounts also consider prior experience in remediating contaminated sites,
other companies' clean-up experience and data released by the Environmental
Protection Agency (EPA) or other organizations. They 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
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 use derivative financial instruments to hedge our cash flow exposure on
our forecasted natural gas sales to changing commodity prices. These derivative
financial instruments consist of primarily swap contracts that require payments
to (or receipts from) counterparties based on the differences between fixed and
variable commodity prices.

     On January 1, 2001, we adopted the provisions of SFAS No. 133, Accounting
for Derivative Instruments and Hedging Activities, in accounting for our
derivative instruments. Under SFAS No. 133, all derivatives are reflected in our
balance sheet as other current assets 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 designate our derivatives as cash flow hedges on the date that we enter
into the derivative contract. Changes in the derivative fair values 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 these hedges is
recognized immediately in earnings as a component of operating revenues in our
income statement.

     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. Our derivative
instruments are linked to the related hedged 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 of the hedged items. We discontinue hedge
accounting prospectively if we determine that a derivative is no longer highly
effective as a hedge.

                                        18
<PAGE>

     The market value of these instruments reflects our best estimate and is
based upon exchange quotations. 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 our derivatives
are recognized in operating cash flows, and any receivables and payables
resulting from these settlements are reported separately from the derivatives in
our balance sheet as trade receivables and payables.

     Prior to our adoption of SFAS No. 133, we applied hedge accounting for our
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. Hedging derivatives were recorded as
gains or losses in operating income and cash inflows and outflows were
recognized in operating cash flow only as the settlement of those transactions
occurred.

  Income Taxes

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

     El Paso maintains a tax sharing policy for companies included in its
consolidated federal income tax return which provides, among other things, that
(i) each company in a taxable income position will be currently charged with an
amount equivalent to its federal income tax computed on a separate return basis,
and (ii) each company in a tax loss position will be reimbursed currently to the
extent its deductions, including general business credits, were utilized in the
consolidated return. Under the policy, El Paso pays all federal income taxes
directly to the IRS and bills or refunds its subsidiaries for their portion of
these income tax payments. Prior to 2001, we had a tax sharing agreement with El
Paso CGP Company which had similar provisions.

  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.

2. MERGER-RELATED COSTS

     During the year ended December 31, 2001, we incurred merger-related costs
of $31 million associated with El Paso's merger with Coastal. Our merger-related
costs consist of employee severance, retention and transition costs for severed
employees and early retirees that occurred as a result of El Paso's
merger-related workforce reduction and consolidation as well as costs for
post-retirement benefits settled and curtailed under existing benefit plans. The
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 employee costs were expensed as incurred and have been paid. Following the
merger, approximately 180 full time positions were eliminated through a
combination of early retirements and terminations. Our merger-related costs also
include charges relating to the valuation of natural gas imbalances to conform
our imbalance valuation methods to El Paso's, the write-off of a software system
that was in development and charges related to a disputed gas pricing claim.
                                        19
<PAGE>

All charges were accrued as of the merger date with the exception of the gas
pricing claim which was expensed when incurred.

3. INCOME TAXES

     The following table reflects the components of income tax expense for each
of the three years ended December 31:

<Table>
<Caption>
                                                              2001   2000   1999
                                                              ----   ----   ----
                                                                (IN MILLIONS)
<S>                                                           <C>    <C>    <C>
Current
  Federal...................................................  $36    $40    $40
  State.....................................................    3      2      3
                                                              ---    ---    ---
                                                               39     42     43
                                                              ---    ---    ---
Deferred
  Federal...................................................   10     21      6
  State.....................................................   (1)     2      1
                                                              ---    ---    ---
                                                                9     23      7
                                                              ---    ---    ---
          Total income tax expense..........................  $48    $65    $50
                                                              ===    ===    ===
</Table>

     Our income tax expense differs from the amount computed by applying the
statutory federal income tax rate of 35 percent to income before taxes for the
following reasons at December 31:

<Table>
<Caption>
                                                              2001   2000   1999
                                                              ----   ----   ----
                                                                (IN MILLIONS)
<S>                                                           <C>    <C>    <C>
Tax expense at the statutory federal rate of 35%............  $49    $63    $48
Increase (decrease)
  State income tax, net of federal income tax benefit.......    1      3      3
  Other.....................................................   (2)    (1)    (1)
                                                              ---    ---    ---
Income tax expense..........................................  $48    $65    $50
                                                              ===    ===    ===
Effective tax rate..........................................   34%    36%    36%
                                                              ===    ===    ===
</Table>

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

<Table>
<Caption>
                                                              2001    2000
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
Deferred tax liabilities
  Property, plant and equipment.............................  $138    $129
  Other.....................................................    15       1
                                                              ----    ----
          Total deferred tax liability......................   153     130
                                                              ----    ----
Deferred tax assets
  Reserve for rate refund and contested claims..............    10      15
  Employee benefits and deferred compensation obligations...     7      --
  Other.....................................................    26      14
                                                              ----    ----
          Total deferred tax asset..........................    43      29
                                                              ----    ----
Net deferred tax liability..................................  $110    $101
                                                              ====    ====
</Table>

     Under El Paso's tax sharing policy, we are allocated the tax benefit
associated with our employees' exercise of non-qualified stock options and the
vesting of restricted stock as well as restricted stock dividends. This
allocation reduced taxes payable by $1 million in 2001. These benefits are
included in additional paid-in capital in our balance sheet.

                                        20
<PAGE>

4. FINANCIAL INSTRUMENTS

  Fair Value of Financial Instruments

     As of December 31, 2001, and 2000, the 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 maturity of these
instruments. We estimated the fair value of debt with fixed interest rates based
on quoted market prices for the same or similar issues.

     The carrying amounts and estimated fair values of our financial instruments
are as follows at 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, including current maturities.......    $280        $306         $280        $299
Other financial instruments:
     Non-Trading instruments(1)
       Commodity swap contracts......................    $  3        $  3         $ --        $ (2)
</Table>

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

(1) 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.

5. ACCOUNTING FOR HEDGING ACTIVITIES

     On January 1, 2001, we adopted the provisions of SFAS No. 133 and recorded
a cumulative unrealized loss of $2 million, net of income taxes, in accumulated
other comprehensive income to recognize the fair value of all derivatives
designated as cash flow hedging instruments. As of December 31, 2001, the value
of cash flow hedges included in accumulated other comprehensive income was an
unrealized gain of $3 million, net of income taxes. We estimate that this amount
will be reclassified to earnings during the next twelve months. Events that will
cause this reclassification relate to the sale of energy commodities. These
deferred amounts, once reclassified into earnings will offset currently
anticipated sales of commodities and will produce a determinable cash flow
stream.

     For the year ended December 31, 2001, no ineffectiveness was recorded in
earnings on our cash flow hedges.

6. LONG-TERM DEBT

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

<Table>
<Caption>
                                                              2001    2000
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
10% Senior Debentures, due 2005.............................  $180    $180
6.85% Senior Debentures, due 2037...........................   100     100
                                                              ----    ----
                                                               280     280
                                                              ----    ----
Long-term debt, less current maturities.....................  $280    $280
                                                              ====    ====
</Table>

                                        21
<PAGE>

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

<Table>
<Caption>
                                                              (IN MILLIONS)
<S>                                                           <C>
2002........................................................      $  --
2003........................................................         --
2004........................................................         --
2005........................................................        180
2006........................................................         --
Thereafter..................................................        100
                                                                  -----
          Total long-term debt, including current
           maturities.......................................      $ 280
                                                                  =====
</Table>

  Other Financing Arrangement

     During 1999, El Paso formed a series of companies referred to as
Clydesdale. Clydesdale was formed to provide financing to invest in various
capital projects and other assets. The proceeds are collateralized by various
fixed assets, including our transmission system.

7. COMMITMENTS AND CONTINGENCIES

  Legal Proceedings

     In 1997, we and a number of our affiliates 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.

     We and a number of our affiliates 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 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 $19 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, as well as our existing accruals,
we do not expect the ultimate resolution of these matters to have a material
adverse effect on our ongoing 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 $7 million for
expected remediation costs. In addition, we expect to make capital expenditures
for environmental matters of approximately $1 million in the

                                        22
<PAGE>

aggregate for the years 2002 through 2006. These expenditures primarily relate
to compliance with clean air regulations.

     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, we filed a rate case with the FERC proposing increased rates
of $9 million annually and new and enhanced services for our customers. This
filing was required under the settlement of our 1996 general rate case. We
received an order from the 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 we had proposed in our rate filing and required us to
reallocate the costs allocated to those two services to existing services. We
have complied with this order and have arranged with the affected customers to
provide service under existing rate schedules. The evidentiary hearing was
suspended pending ongoing attempts to settle the case.

     In September 2001, the FERC issued a Notice of Proposed Rulemaking (NOPR).
The NOPR proposes to apply the standards of conduct governing the relationship
between interstate pipelines and marketing affiliates to all energy affiliates.
The proposed regulations, if adopted by the FERC, would dictate how all our
energy affiliates conduct business and interact with our interstate pipelines.
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 our rate 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.

  Capital Commitments

     At December 31, 2001, we had capital and investment commitments of $139
million primarily related to our Panhandle, Front Range Expansion and Valley
Line Enhancements projects. Our other planned capital and investment projects
are discretionary in nature, with no substantial capital commitments made in
advance of the actual expenditures.

  Operating Leases

     We lease property, facilities and equipment under various operating leases.
The aggregate minimum lease commitments are $2 million for the years 2002 to
2006 with immaterial annual operating lease payments thereafter. These amounts
exclude minimum annual commitments paid by El Paso, which are allocated to us
through an overhead allocation. Rental expense on our operating leases for the
years ended December 31, 2001, 2000 and 1999 was $3 million, $5 million and $5
million.

  Other

     We executed a service agreement with Wyoming Interstate Company, Ltd., our
affiliate, providing for the availability of pipeline transportation capacity
through July 31, 2007. Under the service agreement, we are required to make
minimum payments on a monthly basis with minimum annual payments of $9 million
per year for 2002 through 2004 and $3 million per year for 2005 through 2006,
and $2 million thereafter. We

                                        23
<PAGE>

expensed approximately $9 million, $9 million and $5 million for the years ended
December 31, 2001, 2000 and 1999 related to this agreement.

     We are party to an agreement, known as the Amarillo "B" Contract, under
which we are obligated to sell to Pioneer Natural Resources USA, Inc. (Pioneer)
77 percent of the cumulative natural gas production from specified acreage in
the Panhandle Field of Texas. The remaining production is being sold to other
parties. The agreement remains in effect for as long as the acreage remains
commercially productive. In the event that the acreage becomes commercially
unproductive and Pioneer has not received its 77 percent, we will be required to
make a cash payment to Pioneer for such make-up volume on a price equal to the
higher of our net sales proceeds from this field or a value based on a spot
market index. Based on reserve reports prepared by Huddleston & Co., Inc., an
independent reserve engineering firm, we have not fully produced our 23 percent
share of the total estimated Panhandle Field reserves.

8. RETIREMENT BENEFITS

  Pension and Retirement Benefits

     El Paso maintains a pension plan to provide benefits as determined by a
cash balance formula covering substantially all of its U.S. employees, including
our employees. Also, El Paso maintains a defined contribution plan covering its
U.S. employees, including our employees. El Paso matches 75 percent of
participant basic contributions of up to 6 percent, with matching contributions
made in El Paso common stock, which participants may diversify at any time. El
Paso is responsible for benefits accrued under its plan and allocates the
related costs to its affiliates. See Note 12 for a summary of transactions with
affiliates.

     Prior to our merger with El Paso, Coastal provided non-contributory pension
plans covering substantially all of its U.S. employees, including our employees.
On April 1, 2001, this plan was merged into El Paso's existing plan. Our
employees who were participants in this plan on March 31, 2001 receive the
greater of cash balance benefits under the El Paso plan or Coastal's plan
benefits accrued through March 31, 2006.

  Other Postretirement Benefits

     As a result of El Paso's merger with Coastal, we 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 $8
million. Medical benefits for this closed group of retirees may be subject to
deductibles, co-payment provisions, and other limitations and dollar caps on the
amount of employer costs. El Paso has reserved the right to change these
benefits. Employees who retire on or after June 30, 2001, will continue to
receive limited postretirement life insurance benefits. Our postretirement
benefit plan costs are pre-funded to the extent such costs are recoverable
through rates.

     In January 2001, following the merger, we changed the measurement date for
measuring our other postretirement benefit obligations from December 31 to
September 30. We made this change to conform our measurement date to the date
that El Paso uses to measure other postretirement benefit obligations. The new
method is consistent with the manner in which El Paso gathers other
postretirement 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.

                                        24
<PAGE>

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

<Table>
<Caption>
                                                              2001    2000
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
Change in postretirement benefit obligation
  Benefit obligation at beginning of period.................  $ 15    $ 15
  Interest cost.............................................     1       1
  Participant contributions.................................     1      --
  Plan amendment............................................    (2)     --
  Curtailment and special termination benefits..............     3      --
  Actuarial gain............................................    (2)     --
  Benefits paid.............................................    (1)     (1)
                                                              ----    ----
  Postretirement benefit obligation at end of period........  $ 15    $ 15
                                                              ====    ====
Change in plan assets
  Fair value of plan assets at beginning of period..........  $ 10    $ 10
  Employer contributions....................................     1       1
  Benefits paid.............................................    (1)     (1)
                                                              ----    ----
  Fair value of plan assets at end of period................  $ 10    $ 10
                                                              ====    ====
Reconciliation of funded status
  Funded status at end of period............................  $ (5)   $ (5)
  Fourth quarter contributions..............................     1      --
  Unrecognized actuarial gain...............................    (3)     (4)
  Unrecognized transition obligation........................    --      10
                                                              ----    ----
  Prepaid (accrued) postretirement benefits at December
     31.....................................................  $ (7)   $  1
                                                              ====    ====
</Table>

<Table>
<Caption>
                                                                  YEAR ENDED
                                                                 DECEMBER 31,
                                                              ------------------
                                                              2001   2000   1999
                                                              ----   ----   ----
                                                                (IN MILLIONS)
<S>                                                           <C>    <C>    <C>
Postretirement benefit costs include the following
  components
  Interest cost.............................................   $1     $1     $1
  Amortization of transition obligation.....................   --      1      1
  Curtailment and special termination benefits..............    8     --     --
                                                               --     --     --
  Net postretirement benefit cost...........................   $9     $2     $2
                                                               ==     ==     ==
</Table>

     Postretirement benefit obligations are based upon actuarial estimates as
described below:

<Table>
<Caption>
                                                              2001    2000
                                                              -----   -----
<S>                                                           <C>     <C>
Weighted average assumptions
  Discount rate.............................................  7.25%   7.75%
  Expected return on plan assets............................  7.50%   4.60%
</Table>

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

                                        25
<PAGE>

9. SEGMENT INFORMATION

     Our business activities are segregated into two distinct operating
segments: Pipeline and Field Services. These segments are strategic business
units that provide a variety of energy products and services. They are managed
separately as each business unit requires different technology and marketing
strategies. We measure segment performance using earnings before interest and
income taxes (EBIT). Our historical segments (natural gas systems and
exploration and production) 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. In addition, during
2001, Field Services became a separate segment reflecting the fact that it is
managed separately from our Pipeline segment. The following are our results as
of and for the years ended December 31:

<Table>
<Caption>
                                                       YEAR ENDED DECEMBER 31, 2001
                                               ---------------------------------------------
                                               PIPELINE   FIELD SERVICES   OTHER(1)   TOTAL
                                               --------   --------------   --------   ------
                                                               (IN MILLIONS)
<S>                                            <C>        <C>              <C>        <C>
Revenues from external customers.............  $   366        $ 125          $  6     $  497
Intersegment revenues........................        1            1            (2)        --
Merger-related costs.........................       31           --            --         31
Depreciation, depletion and amortization.....       35            2            --         37
Operating income.............................      123           22             5        150
Other income.................................        3           --            --          3
Earnings before interest and income taxes....      126           22             5        153
Assets.......................................    1,108           78            33      1,219
Capital expenditures and investments in
  unconsolidated affiliates..................      172            3            --        175
Total investments in unconsolidated
  affiliates.................................       --           --            29         29
</Table>

<Table>
<Caption>
                                                        YEAR ENDED DECEMBER 31, 2000
                                                ---------------------------------------------
                                                PIPELINE   FIELD SERVICES   OTHER(1)   TOTAL
                                                --------   --------------   --------   ------
                                                                (IN MILLIONS)
<S>                                             <C>        <C>              <C>        <C>
Revenues from external customers..............   $  338         $30           $20      $  388
Depreciation, depletion and amortization......       28           2             5          35
Operating income..............................      155          14             9         178
Other income (expense)........................        4          --            (1)          3
Earnings before interest and income taxes.....      159          14             8         181
Assets........................................    1,104          53            32       1,189
Capital expenditures and investments in
  unconsolidated affiliates...................       58           3             2          63
Total investments in unconsolidated
  affiliates..................................       33          --            29          62
</Table>

<Table>
<Caption>
                                                        YEAR ENDED DECEMBER 31, 1999
                                                ---------------------------------------------
                                                PIPELINE   FIELD SERVICES   OTHER(1)   TOTAL
                                                --------   --------------   --------   ------
                                                                (IN MILLIONS)
<S>                                             <C>        <C>              <C>        <C>
Revenues from external customers..............   $  271         $28           $12      $  311
Depreciation, depletion and amortization......       21           2             6          29
Operating income..............................      134          11             1         146
Other income..................................        1          --            --           1
Earnings before interest and income taxes.....      135          11             1         147
Assets........................................    1,089          53            44       1,186
Capital expenditures and investments in
  unconsolidated affiliates...................       35           5             6          46
Total investments in unconsolidated
  affiliates..................................       35          --            29          64
</Table>

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

(1) Includes our eliminations and natural gas and oil activities.

                                        26
<PAGE>

     The reconciliations of EBIT to net income are presented below.

<Table>
<Caption>
                                                               FOR THE YEAR ENDED
                                                                  DECEMBER 31,
                                                               ------------------
                                                               2001   2000   1999
                                                               ----   ----   ----
                                                                 (IN MILLIONS)
<S>                                                            <C>    <C>    <C>
Total EBIT for segments.....................................   $153   $181   $147
Non-affiliated interest and debt expense....................     23     24     25
Affiliated interest income, net.............................    (11)   (22)   (15)
Income tax expense..........................................     48     65     50
                                                               ----   ----   ----
          Net income........................................   $ 93   $114   $ 87
                                                               ====   ====   ====
</Table>

10. TRANSACTIONS WITH MAJOR CUSTOMERS

     The following table shows revenues from major customers for each of the
three years ended December 31:

<Table>
<Caption>
                                                              2001(1)     2000     1999
                                                              -------     ----     ----
                                                                    (IN MILLIONS)
<S>                                                           <C>         <C>      <C>
Public Service Company of Colorado..........................    $97       $85      $87
Pioneer Natural Resources USA, Inc..........................     64        49       36
</Table>

11. SUPPLEMENTAL CASH FLOW INFORMATION

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

<Table>
<Caption>
                                                              2001    2000    1999
                                                              ----    ----    ----
                                                                 (IN MILLIONS)
<S>                                                           <C>     <C>     <C>
Interest paid...............................................  $22     $25     $25
Income tax payments.........................................   13      49      44
</Table>

12. INVESTMENTS IN AND TRANSACTIONS WITH RELATED PARTIES

     The following table shows investments in affiliates for each of the three
years ended December 31:

<Table>
<Caption>
                                                    OWNERSHIP
                                                    INTEREST     2001    2000    1999
                                                    ---------    ----    ----    ----
                                                                    (IN MILLIONS)
<S>                                                 <C>          <C>     <C>     <C>
Coastal Medical Services, Inc.....................     --%       $ --    $ 33    $ 35
Coastal Limited Ventures, Inc.....................      4%         14      14      14
Coastal Oil and Gas Resources, Inc................      4%         15      15      15
                                                                 ----    ----    ----
       Total......................................               $ 29    $ 62    $ 64
                                                                 ====    ====    ====
</Table>

     In 1996, Coastal Medical Services Inc. was formed to improve the value of
Coastal's medical benefit program for its employees and employees of its
subsidiaries by managing the medical obligations of its participating
subsidiaries. Coastal Medical Services was created through the contribution of
cash by 25 El Paso CGP subsidiaries in exchange for Coastal Medical Services
stock. We accounted for the investment using the cost method since we did not
have ability to exert significant influence over operating or managing decisions
of Coastal Medical Services. In December 2001, we redeemed our 4 percent
ownership interest in Coastal Medical Services and recorded dividend income of
$3 million.

     In 1999, we transferred a production payment and the properties burdened by
the production payment to Coastal Limited Ventures, Inc. and Coastal Oil and Gas
Resources Inc., two separate subsidiaries of Coastal, in exchange for a 4
percent interest in the common stock of each subsidiary. We accounted for the
exchange at historical cost since it occurred between entities under common
control. We accounted for the investment in each of the affiliated companies
using the cost method since we did not have the ability to exert significant

                                        27
<PAGE>

influence over their operating or management decisions. The total investment was
$29 million as of December 2001 and 2000.

     We participate in El Paso's cash management program which matches
short-term cash surpluses and needs of its participating affiliates, thus
minimizing total borrowing from outside sources. We had advanced $232 million at
December 31, 2001, at a market rate of interest which was 2.1%. At December 31,
2000, we had advanced $331 million at a market rate of interest which was 7.3%.

     At December 31, 2001 and 2000, we had accounts receivable from affiliates
of $48 million and $18 million. In addition, we had accounts payable to
affiliates of $10 million and $9 million at December 31, 2001 and 2000. These
balances were incurred in the normal course of our business.

     El Paso allocated a portion of its general and administrative expenses to
us in 2001. 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. In 2000 and 1999, we
performed most of our own administrative functions and provided some
administrative functions for our affiliates. As a result, our allocated
administrative expenses were lower and our reimbursement of costs were higher
than in 2001.

     Beginning after the merger in 2001, we entered into transactions with other
El Paso subsidiaries in the ordinary course of our business to transport, sell
and purchase natural gas which increased our affiliated revenue and charges.
Services provided by these affiliates for our benefit are based on the same
terms as non-affiliates.

     The following table shows revenues and charges from our affiliates for each
of the three years ended December 31:

<Table>
<Caption>
                                                              2001   2000   1999
                                                              ----   ----   ----
<S>                                                           <C>    <C>    <C>
Revenues....................................................  $191   $89    $68
Charges.....................................................   106    16     13
Reimbursement for costs.....................................     1     7     10
</Table>

13. SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

     Financial information by quarter is summarized below.

<Table>
<Caption>
                                                       OPERATING      OPERATING       NET
                       QUARTER                         REVENUES        INCOME        INCOME
                       -------                         ---------      ---------      ------
                                                                    (IN MILLIONS)
<S>                                                    <C>          <C>              <C>
2001
  1st................................................    $125           $ 47          $ 29
  2nd................................................     132             18            10
  3rd................................................     118             38            22
  4th................................................     122             47            32
                                                         ----           ----          ----
                                                         $497           $150          $ 93
                                                         ====           ====          ====
2000
  1st................................................    $ 93           $ 50          $ 31
  2nd................................................      84             32            20
  3rd................................................      79             25            16
  4th................................................     132             71            47
                                                         ----           ----          ----
                                                         $388           $178          $114
                                                         ====           ====          ====
</Table>

14. SUPPLEMENTAL NATURAL GAS AND OIL OPERATIONS (UNAUDITED)

     For purposes of the Supplemental Natural Gas and Oil Operations disclosure,
we have presented reserves, the standardized measure of discounted future net
cash flows and the related changes in standardized measure separately for our
Pipeline segment's production activities. The Supplemental Natural Gas and Oil

                                        28
<PAGE>

Operations disclosure does not include any value for the Pipeline segment
storage gas and liquids volumes managed by our pipeline segment.

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

<Table>
<Caption>
                                                              2001    2000
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
Natural gas and oil properties:
  Costs subject to amortization.............................  $163    $ 99
  Costs not subject to amortization.........................     1       1
                                                              ----    ----
                                                               164     100
Less accumulated DD&A.......................................   163      96
                                                              ----    ----
Net capitalized costs.......................................  $  1    $  4
                                                              ====    ====
</Table>

     During the years ended December 31, 2001, 2000 and 1999, we incurred costs
in our natural gas and oil producing activities, substantially all of which were
development costs, of less than $1 million, $2 million and $6 million. In
addition, as of December 31, 2001, 2000 and 1999, we had less than $1 million in
capitalized acquisition costs that were not being amortized in our full cost
pool. The majority of these costs are expected to be included in the
amortization calculation in the years 2002 through 2004. Total amortization
expense per Mcfe was $1.03, $1.015, and $0.87 in 2001, 2000, and 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. All of our proved properties are located in the United
States.

                                        29
<PAGE>

<Table>
<Caption>
                                                      NATURAL GAS            LIQUIDS(1)
                                                  --------------------    -----------------
                                                  PIPELINE                PIPELINE
                                                  SEGMENT      OTHER      SEGMENT     OTHER
                                                  --------    --------    --------    -----
                                                         (BCF)                 (MBBLS)
<S>                                               <C>         <C>         <C>         <C>
Net proved developed and undeveloped reserves(2)
  January 1, 1999...............................    212          113         237       550
     Revisions of previous estimates............     22         (100)         36      (330)
     Extensions, discoveries and other..........     --            1          --        19
     Purchases of reserves in place.............     --           --          --        --
     Sales of reserves in place.................     --           --          --        --
     Production.................................    (36)          (5)        (24)      (80)
                                                    ---         ----        ----      ----
  December 31, 1999.............................    198            9         249       159
     Revisions of previous estimates............     11            5           7       110
     Extensions, discoveries and other..........     --           --          --        --
     Purchases of reserves in place.............     --           --          --        --
     Sales of reserves in place.................     --           (1)         --        --
     Production.................................    (33)          (4)        (25)     (160)
                                                    ---         ----        ----      ----
  December 31, 2000.............................    176            9         231       109
     Revisions of previous estimates............     37           (3)       (118)      (59)
     Extensions, discoveries and other..........     --           --          --        --
     Purchases of reserves in place.............     --           --          --        --
     Sales of reserves in place.................     --           --          --        --
     Production.................................    (30)          (1)        (16)      (13)
                                                    ---         ----        ----      ----
  December 31, 2001.............................    183            5          97        37
                                                    ===         ====        ====      ====
Proved developed reserves
  December 31, 1999.............................    198            7         249       140
  December 31, 2000.............................    176            6         231        81
  December 31, 2001.............................    183            2          97         8
</Table>

---------------
(1) Includes oil, condensate and natural gas liquids.

(2) 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.

                                        30
<PAGE>

  Results of operations from producing activities by fiscal year were as
  follows:

<Table>
<Caption>
                                                                  YEAR ENDED
                                                                 DECEMBER 31,
                                                              ------------------
                                                              2001   2000   1999
                                                              ----   ----   ----
                                                                (IN MILLIONS)
<S>                                                           <C>    <C>    <C>
Net revenues:
  Sales to external customers...............................  $ 3    $15    $  3
  Affiliated sales..........................................    3      1       9
                                                              ---    ---    ----
     Total..................................................    6     16      12
Production costs............................................   (1)    (3)     (5)
Depreciation, depletion and amortization....................   --     (4)     (5)
                                                              ---    ---    ----
                                                                5      9       2
Income tax (expense) benefit................................   (2)    (3)      1
                                                              ---    ---    ----
Results of operations for producing activities (excluding
  corporate overhead and interest costs)....................  $ 3    $ 6    $  3
                                                              ===    ===    ====
</Table>

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

<Table>
<Caption>
                                                        2001                  2000               1999
                                                ---------------------   ----------------   ----------------
                                                 PIPELINE               PIPELINE           PIPELINE
                                                 SEGMENT      OTHER     SEGMENT    OTHER   SEGMENT    OTHER
                                                ----------   --------   --------   -----   --------   -----
                                                                       (IN MILLIONS)
<S>                                             <C>          <C>        <C>        <C>     <C>        <C>
Future cash inflows...........................     $313       $  14      $ 474     $ 53      $229      $20
Future production and development costs.......      (64)         (3)      (110)      (7)      (74)      (7)
Future income tax (expenses) benefits.........      (83)         17       (116)     (10)      (49)       3
                                                   ----       -----      -----     ----      ----      ---
Future net cash flows.........................      166          28        248       36       106       16
10% annual discount for estimated timing of
  cash flows..................................      (72)         (9)       (89)     (10)      (41)      (2)
                                                   ----       -----      -----     ----      ----      ---
Standardized measure of discounted future net
  cash flows..................................     $ 94       $  19      $ 159     $ 26      $ 65      $14
                                                   ====       =====      =====     ====      ====      ===
</Table>

     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
changes in prices, the amounts realized based on our hedging strategies and
changes in production or reserve estimates.

     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.

                                        31
<PAGE>

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

<Table>
<Caption>
                                                        2001                  2000               1999
                                                ---------------------   ----------------   ----------------
                                                 PIPELINE               PIPELINE           PIPELINE
                                                 SEGMENT      OTHER     SEGMENT    OTHER   SEGMENT    OTHER
                                                ----------   --------   --------   -----   --------   -----
                                                                       (IN MILLIONS)
<S>                                             <C>          <C>        <C>        <C>     <C>        <C>
Sales and transfers of oil and gas produced
  net of production costs.....................    $(255)       $ (5)      $(52)    $(15)     $(36)    $ (8)
Net changes in prices and production costs....       10         (15)       150       10        (6)      13
Extensions, discoveries and improved recovery,
  less related costs..........................       --          --         --       --        --        1
Changes in estimated future development
  costs.......................................       13           1         --       --        --       --
Development costs incurred during the
  period......................................       --          --         --       --        --        2
Revisions of previous quantity estimates......       39          (5)        34       25        28      (56)
Accretion of discount.........................       23           3          4       --         7        5
Net change in income taxes....................       25          16        (42)      (8)        3        8
Change in production rates, timing and
  other.......................................       80          (2)        --       --        --       --
                                                  -----        ----       ----     ----      ----     ----
Net change....................................    $ (65)       $ (7)      $ 94     $ 12      $ (4)    $(35)
                                                  =====        ====       ====     ====      ====     ====
</Table>

                                        32
<PAGE>

                       REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and Stockholder of
El Paso Colorado Interstate Gas 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 Colorado Interstate Gas 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 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 5, 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 date used to
account for 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.

/s/ PricewaterhouseCoopers LLP
Houston, Texas
March 6, 2002

                                        33
<PAGE>

                          INDEPENDENT AUDITORS' REPORT

Board of Directors and Stockholder
Colorado Interstate Gas Company
Colorado Springs, Colorado

     We have audited the consolidated balance sheets of Colorado Interstate Gas
Company (an indirect, wholly owned subsidiary 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. 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 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 Colorado
Interstate Gas 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.

/s/ Deloitte & Touche LLP

Denver, Colorado
February 23, 2001

                                        34
<PAGE>

                                  SCHEDULE II

                        COLORADO INTERSTATE GAS COMPANY

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

<Table>
<Caption>
                                        BALANCE AT    CHARGED TO    CHARGED TO                   BALANCE
                                        BEGINNING     COSTS AND       OTHER                      AT END
             DESCRIPTION                OF PERIOD      EXPENSES      ACCOUNTS     DEDUCTIONS    OF PERIOD
             -----------                ----------    ----------    ----------    ----------    ---------
<S>                                     <C>           <C>           <C>           <C>           <C>
2001
  Legal Reserves......................     $22           $ --          $ (3)         $--           $19
  Environmental Reserves..............       4             --             3           --             7
  Regulatory Reserves.................      --              5            --           --             5
2000
  Legal Reserves......................     $42           $(17)(1)      $ (3)         $--           $22
  Environmental Reserves..............       1             --             3           --             4
1999
  Legal Reserves......................     $42           $ --          $ --          $--           $42
  Environmental Reserves..............       1             --            --           --             1
</Table>

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

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

                                        35
<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 and supplemental information.

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

<Table>
<Caption>
                                                              PAGE
                                                              ----
<S>                                                           <C>
Consolidated Statements of Income...........................   12
Consolidated Balance Sheets.................................   13
Consolidated Statements of Cash Flows.......................   14
Consolidated Statements of Stockholder's Equity.............   15
Notes to Consolidated Financial Statements..................   16
Report of Independent Accountants...........................   33
</Table>

     2. Financial statement schedules.

<Table>
<S>                                                           <C>
          Schedule II -- Valuation and qualifying
           accounts.........................................   35
          Schedules other than that listed above are omitted
        because they are not applicable.

     3. Exhibit list........................................   37
</Table>

     (B) REPORTS ON FORM 8-K.

     None.

                                        36
<PAGE>

                        COLORADO INTERSTATE GAS COMPANY

                                  EXHIBIT LIST
                               DECEMBER 31, 2001

     Exhibits not incorporated by reference to a prior filing are designated by
an asterisk. All exhibits not so designated are incorporated herein by reference
to a prior filing as indicated.

<Table>
<Caption>
        EXHIBIT
         NUMBER                                  DESCRIPTION
        -------                                  -----------
<C>                      <S>
          *3.A           -- Amended and Restated Certificate of Incorporation dated
                            as of March 7, 2002.
          *3.B           -- By-Laws dated March 7, 2002.
         *18             -- Letter regarding Change in Accounting Principle
         *99.1           -- Report of Independent Accountants, PricewaterhouseCoopers
                            LLP
         *99.2           -- Independent Auditors' Report, Deloitte & Touche LLP
</Table>

REPORTS ON FORM 8-K

     None.

UNDERTAKING

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

                                        37
<PAGE>

                                   SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, as amended, Colorado Interstate Gas 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.

                                          COLORADO INTERSTATE GAS COMPANY

                                          By   /s/ JOHN W. SOMERHALDER II
                                            ------------------------------------
                                                   John W. Somerhalder II
                                                   Chairman of the Board

     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
Colorado Interstate Gas Company and in the capacities and on the dates
indicated:

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

                /s/ JOHN W. SOMERHALDER II                    Chairman of the Board, Chief        March 28, 2002
 --------------------------------------------------------       Executive Officer and Director
                 (John W. Somerhalder II)                       (Principal Executive Officer)

                 /s/ PATRICIA A. SHELTON                      President and Director              March 28, 2002
 --------------------------------------------------------
                  (Patricia A. Shelton)

                    /s/ GREG G. GRUBER                        Senior Vice President, Chief        March 28, 2002
 --------------------------------------------------------       Financial Officer and Treasurer
                     (Greg G. Gruber)                           (Principal Financial and
                                                                Accounting Officer)
</Table>

                                        38
<PAGE>

                                 EXHIBIT INDEX

     Exhibits not incorporated by reference to a prior filing are designated by
an asterisk. All exhibits not so designated are incorporated herein by reference
to a prior filing as indicated.

<Table>
<Caption>
        EXHIBIT
         NUMBER                                  DESCRIPTION
        -------                                  -----------
<C>                      <S>

          *3.A           -- Amended and Restated Certificate of Incorporation dated
                            as of March 7, 2002.
          *3.B           -- By-Laws dated March 7, 2002.
         *18             -- Letter regarding Change in Accounting Principle
         *99.1           -- Report of Independent Accountants, PricewaterhouseCoopers
                            LLP
         *99.2           -- Independent Auditors' Report, Deloitte & Touche LLP
</Table>

                                        39