<PAGE>

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

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

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

                                   FORM 10-K

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

                  FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002

                                       OR

      [ ]      TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934

                FOR THE TRANSITION PERIOD FROM        TO

                         COMMISSION FILE NUMBER 1-4874

                        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>

                       TELEPHONE NUMBER:  (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 (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.  Yes [X]  No [ ]

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

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

     STATE THE AGGREGATE MARKET VALUE OF THE VOTING 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, par value $1 per share. Shares outstanding on March 27, 2003:
1,000

     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..................................................      4
Item 3.    Legal Proceedings...........................................      4
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.......................................      4
Item 6.    Selected Financial Data.....................................      *
Item 7.    Management's Discussion and Analysis of Financial Condition
             and Results of Operations.................................      5
           Risk Factors and 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......................................................     16
Item 8.    Financial Statements and Supplementary Data.................     17
Item 9.    Changes in and Disagreements with Accountants on Accounting
             and Financial Disclosure..................................     41

                                   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..............      *
Item 14.   Controls and Procedures.....................................     41

                                    PART IV
Item 15.   Exhibits, Financial Statement Schedules, and Reports on Form
             8-K.......................................................     43
           Signatures..................................................     45
           Certifications..............................................     46
</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
Bcf      = billion cubic feet
Btu      = British thermal unit
Mcf      = thousand cubic feet
MMcf     = million cubic feet
</Table>

     When we refer to cubic feet measurements, all measurements are at a
pressure of 14.73 pounds per square inch.

     When we refer to "us", "we", "our", 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 (El Paso) through the
merger of a wholly owned El Paso subsidiary with El Paso CGP Company (El Paso
CGP), formerly The Coastal Corporation (Coastal). On June 29, 2001, all of our
outstanding common stock was contributed by 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. Our primary business is the
ownership and operation of an interstate natural gas pipeline system, natural
gas processing facilities and gathering systems.

                                    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 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 11, which is incorporated herein by
reference. On July 1, 2002, we sold our interests in natural gas and oil
production properties and contracts located in Texas, Kansas and Oklahoma to
Pioneer Natural Resources USA, Inc. and affiliates (Pioneer). We also executed
an agreement with Pioneer to sell a federally regulated natural gas gathering
system in the Panhandle field of Texas. These assets were historically included
in our Pipeline segment and as a result of the sale, we reclassified all
activities associated with these assets as discontinued operations. For a
further discussion of the sale, see Part II, Item 8, Financial Statements and
Supplementary Data, Note 2.

PIPELINE SEGMENT

     Our Pipeline segment provides natural gas transmission, storage and
processing services and consists of approximately 4,000 miles of pipeline with a
design capacity of approximately 3,100 MMcf/d. During 2002, 2001 and 2000,
average throughput was 1,525 BBtu/d, 1,359 BBtu/d and 1,291 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 interconnects with several
pipeline systems transporting gas to the Midwest, the Southwest, California and
the Pacific Northwest. Along our system, we have approximately 29 Bcf of
underground working gas storage capacity. In 2002, we completed a number of
expansion projects, including the Front Range Expansion and Raton Basin
Expansion projects. These projects installed compression and pipeline looping to
increase deliverability along the Colorado Front Range market area and to
increase exports from the Raton Basin. These projects added approximately 317
MMcf/d to our capacity.

     On February 20, 2003, we were authorized by the Federal Energy Regulatory
Commission (FERC) to construct and operate additional gas compression and air
blending facilities necessary to expand the deliverability of the Valley Line
portion of our Front Range system by a total of approximately 92 MMcf/d. The
in-service date for these facilities is expected to be during the fourth quarter
of 2003.

     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 FERC-approved tariff that establishes rates and terms
and conditions for services to our customers. Generally, the FERC's authority
extends to:

     - rates and charges for natural gas transportation and storage;

     - certification and construction of new facilities;

     - extension or abandonment of facilities;

                                        1
<PAGE>

     - maintenance of accounts and records;

     - relationships between pipeline and marketing affiliates;

     - terms and conditions of services;

     - depreciation and amortization policies;

     - acquisition and disposition of facilities; and

     - initiation and discontinuation of services.

     The fees or rates established under our tariffs are a function of our costs
of providing services to our customers, as well as a reasonable return on our
invested capital. Approximately 90 percent of our transportation services
revenue is attributable to a capacity reservation, or demand charge, paid by
firm customers. These firm customers are obligated to pay a monthly demand
charge, regardless of the amount of natural gas they transport or store, for the
term of their contracts. The remaining 10 percent of our transportation services
revenue is primarily attributable to charges based solely on the volumes of gas
actually transported or stored on our pipeline system. Consequently, our
financial results have historically been relatively stable; however, they can be
subject to volatility due to factors such as weather, changes in natural gas
prices and market conditions, regulatory actions, competition and the
credit-worthiness of our customers.

     Our interstate pipeline system is also subject to federal, state and local
pipeline safety and environmental statutes and regulations. We have continuing
programs designed to keep all of our facilities in compliance with pipeline
safety and environmental requirements. We believe that our system is in material
compliance with the applicable requirements.

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

     Markets and Competition.  We have approximately 125 firm and interruptible
customers, including distribution and industrial customers, electric generation
companies, gas producers, other gas pipelines and gas marketing and trading
companies. We provide transportation services in both our gas supply and market
areas. We have approximately 170 firm transportation contracts with an average
remaining term of approximately seven years. Substantially all of our firm
capacity is fully subscribed. The largest customer we served during 2002 was
Public Service Company of Colorado with a capacity of 1,557 BBtu/d under
contracts that expire between 2007 and 2025. Of this amount, 1,095 BBtu/d
expires in 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, as well as from alternate energy sources used to generate
electricity such as hydroelectric, coal and fuel oil. Competition for the
on-system market consists of local production from the Denver-Julesburg basin,
an intrastate pipeline, and long-haul shippers who elect to sell into this
market rather than the off-system market. Recent growth in the on-system market
from both the space heating segment and electric generation segment has provided
us with incremental demand for transportation services. Competition for the
off-system market consists of other interstate pipelines that are directly
connected to our supply sources and transport these volumes to markets in the
West, Northwest, Southwest and Midwest. The Rockies region has experienced
substantial growth in production, which has resulted in a situation where supply
is greater than the currently available transportation export capacity.

     Electric power generation is one of the fastest growing demand sectors of
the natural gas market. The potential consequences of proposed and ongoing
restructuring and deregulation of the electric power industry are currently
unclear. Restructuring and deregulation benefit the natural gas industry by
creating more demand for natural gas turbine generated electric power, but this
effect is offset, in varying degrees, by increased generation efficiency and
more effective use of surplus electric capacity as a result of open market
access.

                                        2
<PAGE>

     Our ability to extend our existing contracts or re-market expiring capacity
is dependent on competitive alternatives, the regulatory environment at the
federal, state and local levels and market supply and demand factors at the
relevant dates these contracts are extended or expire. The duration of new or
re-negotiated contracts will be affected by current prices, competitive
conditions and judgments concerning future trends and volatility. We attempt to
resubscribe our capacity at the maximum rates allowed under our tariff; however,
at times we discount our rates to remain competitive.

FIELD SERVICES SEGMENT

     Our Field Services segment provides midstream services in the Rocky
Mountain and Mid-Continent regions, including natural gas gathering and
processing. Our natural gas gathering and processing facilities are located
throughout the production areas adjacent to our transmission system. During
2002, we owned and operated various gathering lines, field compressors and
gathering systems which gathered 404 BBtu/d, 451 BBtu/d and 510 BBtu/d for the
years ended December 31, 2002, 2001 and 2000.

     We own and operate one natural gas processing plant which has operating
capacity of 13 BBtu/d. We also have processing arrangements with 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.

     In December 2002, we sold our Natural Buttes gas gathering facilities which
included 225 miles of natural gas gathering pipelines with approximately 140
MMcf/d of capacity. These assets gathered 117 BBtu/d for the year ended December
31, 2002. In January 2003, we sold several of our small gathering systems
located in Wyoming, which included 450 miles of natural gas gathering pipelines
with a capacity of 215 MMcf/d. These assets gathered 125 BBtu/d for the year
ended December 31, 2002. In March 2003, we received appropriate management
approval to sell our remaining assets in the Mid-Continent region. These assets
primarily include our Greenwood, Hugoton, Keyes and Mocane natural gas gathering
systems which include 1,680 miles of natural gas gathering pipelines. These
gathering systems have a capacity of 225 MMcf/d and gathered 162 BBtu/d for the
year ended December 31, 2002. Our processing plant and arrangements at three
additional processing plants are also included in the proposed sale. We expect
this sale to close by the end of 2003.

     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 continuing programs
designed to keep all of the facilities in compliance with environmental and
pipeline safety requirements, and we believe that our systems are in material
compliance with the 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.

                                 ENVIRONMENTAL

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

                                   EMPLOYEES

     As of March 26, 2003, we had approximately 240 full-time employees, none of
whom are subject to a collective bargaining agreement.

                                        3
<PAGE>

ITEM 2. PROPERTIES

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

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

ITEM 3. LEGAL PROCEEDINGS

     A description of our legal proceedings is included in Part II, Item 8,
Financial Statements and Supplementary Data, Note 8, 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

     All of our common stock, par value $1 per share, is owned by Noric III and,
accordingly, there is no public trading market for our common stock. Noric III,
is an indirect subsidiary of El Paso CGP. On January 29, 2001, El Paso CGP
became a wholly owned subsidiary of El Paso.

     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 to our parent in 2001. No common stock
dividends were declared or paid in 2002.

     On February 7, 2003 we declared and paid a cash dividend of approximately
$41 million.

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.

                                        4
<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.

                                    GENERAL

     Our business consists of interstate natural gas transportation, storage,
processing and gathering. Our interstate natural gas transportation system faces
varying degrees of competition from other pipelines, as well as from alternate
energy sources used to generate electricity, such as hydroelectric power, coal
and fuel oil. We are regulated by the FERC which regulates the rates we can
charge our customers. These rates are a function of our costs of providing
services to our customers, and include a return on our invested capital. As a
result, our financial results have historically been relatively stable; however,
they can be subject to volatility due to factors such as weather, changes in
natural gas prices and market conditions, regulatory actions, competition and
the credit-worthiness of our customers. In addition, our ability to extend our
existing customer contracts or re-market expiring contracted capacity at maximum
rates is dependent on competitive alternatives, the regulatory environment and
supply and demand factors at the relevant dates these contracts are extended or
expire. We attempt to resubscribe our capacity at the maximum rates allowed
under our tariff; however, at times we discount our rates to remain competitive.

                             RESULTS OF OPERATIONS

     We use EBIT to assess the operating results and effectiveness of our
business segments. We define EBIT as operating income, adjusted for gains and
losses on sales of assets and other miscellaneous non-operating items. Items
that are not included in this measure are financing costs, including interest
and debt expense, affiliated interest income, income taxes and discontinued
operations. Below is a reconciliation of operating results to EBIT and income
from continuing operations for the year ended December 31:

<Table>
<Caption>
                                                              2002    2001
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
  Operating revenues........................................  $ 383   $ 376
  Operating expenses........................................   (229)   (286)
                                                              -----   -----
       Operating income.....................................    154      90
                                                              -----   -----
  Net gain on sale of assets................................     26      --
  Affiliated dividend income................................     14       3
                                                              -----   -----
       Other................................................     40       3
                                                              -----   -----
       EBIT.................................................    194      93
  Interest and debt expense.................................    (23)    (23)
  Affiliated interest income................................      4      11
  Income taxes..............................................    (59)    (26)
                                                              -----   -----
       Income from continuing operations....................  $ 116   $  55
                                                              =====   =====
</Table>

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

                                        5
<PAGE>

SEGMENT RESULTS

     Our Pipeline and Field Services segments are strategic business units that
offer different energy services and require different marketing strategies.
Operating revenues and expenses by segment include intersegment revenues and
expenses which have been eliminated in consolidation. On July 1, 2002, we sold
our interests in natural gas and oil production contracts and properties located
in Texas, Kansas and Oklahoma to Pioneer. We also executed an agreement with
Pioneer to sell a federally regulated natural gas gathering system in the
Panhandle field of Texas and completed the sale of the gathering system in
February 2003. These assets were historically included in our Pipeline segment
and as a result of the sale, we reclassified all activities associated with
these assets as discontinued operations. For a further discussion of the sale
and our individual segments, see Part II, Item 8, Financial Statements and
Supplementary Data, Notes 2 and 11. The following table presents EBIT by segment
and in total for each of the years ended December 31:

<Table>
<Caption>
                                                              2002    2001
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
  Pipeline..................................................  $141     $66
  Field Services............................................    39      22
                                                              ----     ---
       Segment total........................................   180      88
  Other operations..........................................    14       5
                                                              ----     ---
       Consolidated EBIT from continuing operations.........  $194     $93
                                                              ====     ===
</Table>

  PIPELINE

     Our Pipeline segment includes our interstate natural gas transmission,
storage and processing businesses. Our interstate natural gas transmission
system faces varying degrees of competition from other pipelines, as well as
from alternative energy sources used to generate electricity, such as
hydroelectric power, coal and fuel oil. We are regulated by the FERC, which
regulates the rates we can charge our customers. These rates are a function of
our costs of providing service to our customers, and include a return on our
invested capital. Our financial results have historically been relatively
stable; however, they can be subject to volatility due to factors such as
weather, changes in natural gas prices and market conditions, regulatory
actions, competition and the credit-worthiness of our customers. In addition,
our ability to extend our existing customer contracts or re-market expiring
contracted capacity at maximum rates is dependent on competitive alternatives,
the regulatory environment and market supply and demand factors at the relevant
dates these contracts are extended or expire. We attempt to resubscribe our
capacity at the maximum rates allowed under our tariff; however, at times we
discount our rates to remain competitive.

     Results of our Pipeline segment operations were as follows for the year
ended December 31:

<Table>
<Caption>
                                                                2002        2001
                                                              ---------   ---------
                                                              (IN MILLIONS, EXCEPT
                                                                 VOLUME AMOUNTS)
<S>                                                           <C>         <C>
Operating revenues..........................................   $  247      $  245
Operating expenses..........................................     (107)       (182)
Other income................................................        1           3
                                                               ------      ------
     EBIT...................................................   $  141      $   66
                                                               ======      ======
Throughput volumes (BBtu/d)(1)..............................    1,525       1,359
                                                               ======      ======
</Table>

---------------
(1) Throughput volumes exclude those related to discontinued operations.

     Operating revenues for the year ended December 31, 2002, were $2 million
higher than 2001. Our reservation revenues increased $16 million during 2002 due
to completed system expansions as well as changes in our tariff rates that
provide for a higher portion of our revenues to be collected through reservation
charges instead of throughput-based rates. This increase was partially offset by
lower prices and volumes on our liquids sales which totaled $9 million, and a $6
million decrease in throughput-based revenues.

                                        6
<PAGE>

     Operating expenses for the year ended December 31, 2002, were $75 million
lower than 2001. A decrease of $33 million was due to reduced gas costs for our
system supply operating needs during 2002. Also contributing to the decrease was
$31 million of merger-related costs incurred as part of El Paso's merger with
our former parent company in January 2001 (for a discussion of these costs, see
Item 8, Financial Statements and Supplementary Data, Note 3) and $14 million
from reduced corporate allocations in 2002.

  FIELD SERVICES

     The Field Services segment provides midstream natural gas services in the
Rocky Mountain and Mid-Continent regions, including gathering and processing of
natural gas. The gathering 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, our Field Services segment may have more sensitivity
to price changes during periods when natural gas and natural gas liquids prices
are volatile. 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.

     In December 2002, we sold the Natural Buttes gas gathering facilities to
Westport Resources Corporation. These assets generated EBIT of $5 million during
the year ended December 31, 2002.

     In January 2003, we sold several small gathering systems located in Wyoming
to Western Gas Resources, Inc. These assets generated EBIT of approximately $5
million during the year ended December 31, 2002. These assets are classified as
assets held for sale as of December 31, 2002.

     In March 2003, we received appropriate management approval to sell our
remaining assets in the Mid-Continent region. These assets primarily include our
Greenwood, Hugoton, Keyes and Mocane natural gas gathering systems, our
processing plant and our processing arrangements at three additional processing
plants. These assets generated EBIT of approximately $4 million during the year
ended December 31, 2002. We expect this sale to close by the end of 2003. After
this sale is completed, we will no longer have any operating assets in this
segment.

     Results of our Field Services segment operations were as follows for the
year ended December 31:

<Table>
<Caption>
                                                              2002     2001
                                                              -----    -----
                                                              (IN MILLIONS,
                                                              EXCEPT VOLUMES
                                                               AND PRICES)
<S>                                                           <C>      <C>
Gathering and processing gross margins......................  $  25    $  31
Operating expenses..........................................    (11)      (9)
Other income................................................     25       --
                                                              -----    -----
     EBIT...................................................  $  39    $  22
                                                              =====    =====
Volumes and prices
  Gathering and treating
     Volumes (BBtu/d).......................................    404      451
                                                              =====    =====
     Prices ($/MMBtu).......................................  $0.14    $0.17
                                                              =====    =====
</Table>

     Total gross margins for the year ended December 31, 2002, were $6 million
lower than 2001. The decrease was due to lower gathering volumes and lower
realized natural gas prices in 2002. Volumes were lower due to natural declines
in natural gas production in our operating regions.

     Other income for the year ended December 31, 2002, was $25 million higher
than 2001 due to the gain on the sale of our Natural Buttes gas gathering
facilities in December 2002.

                                        7
<PAGE>

  OTHER OPERATIONS

     Our other operations consist of investments in unconsolidated affiliates
and a minor amount of natural gas and oil production properties located in South
Texas that we owned. During 2002, we received $14 million in affiliated dividend
income. Income from our natural gas and oil production activities was less than
$1 million versus $5 million in 2001. During 2002, we sold our natural gas and
oil properties to our parent (El Paso CGP). In addition, we sold or liquidated
our investments in unconsolidated affiliates in the fourth quarter of 2002. See
Item 8, Financial Statements and Supplementary Data, Notes 2 and 14 for further
discussions of these transactions.

AFFILIATED INTEREST INCOME

     Affiliated interest income for the year ended December 31, 2002, was $7
million lower than the same period in 2001. The decrease was due to lower
short-term interest rates in 2002 and lower average advances to El Paso under
its cash management program. The average short-term interest rates for the
twelve months decreased from 4.3% in 2001 to 1.8% in 2002, and the average
advance balances decreased from $257 million in 2001 to $230 million in 2002.

INCOME TAXES

     Income tax expense from continuing operations for the years ended December
31, 2002 and 2001, was $59 million and $26 million, resulting in effective tax
rates of 34 percent and 32 percent. Our effective tax rates differed from the
statutory rate of 35 percent in both periods primarily due to the impact of
state income taxes and affiliated dividend income. For a reconciliation of the
statutory rate of 35 percent to the effective tax rates, see Item 8, Financial
Statements and Supplementary Data, Note 4.

                        LIQUIDITY AND CAPITAL RESOURCES

  LIQUIDITY

     Our liquidity needs are provided by cash flow from operating activities and
the use of El Paso's cash management program. Under El Paso's cash management
program, depending on whether we have short-term cash surpluses or requirements,
we either provide cash to El Paso or El Paso provides cash to us. We have
historically provided cash advances to El Paso, and we reflect these activities
as investing activities in our statement of cash flows. As of December 31, 2002,
we had receivables from El Paso and affiliates of $469 million as a result of
this program. These receivables are due upon demand. However, $444 million is
classified as non-current because we do not anticipate settlement within twelve
months. We believe that cash flow from operating activities and cash provided by
El Paso's cash management program will be adequate to meet our short-term
capital requirements for existing operations. Our cash flows from continuing
operations for the years ended December 31 were as follows:

<Table>
<Caption>
                                                               YEAR ENDED
                                                              -------------
                                                              2002    2001
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
Cash flows from operating activities........................  $ 167   $ 150
Cash flows from investing activities........................   (302)    (25)
Cash flows from financing activities........................    145    (125)
</Table>

     In a series of credit rating agency actions in late 2002 and early 2003,
and contemporaneously with the downgrades of the senior unsecured indebtedness
of El Paso, our senior unsecured indebtedness was downgraded to below investment
grade and is currently rated B1 by Moody's and B+ by Standard & Poor's with a
negative outlook from both agencies. These downgrades will increase our cost of
capital and collateral requirements and could impede our access to capital
markets in the future.

     These downgrades prevent us from providing our excess cash to El Paso under
its cash management program. Each quarter, our parent company is required to pay
from these excess funds a specified amount

                                        8
<PAGE>

(based on our cash-based earnings) to retire the amounts outstanding under an El
Paso financing arrangement which is referred to as Clydesdale and collateralized
by us and other El Paso affiliates. In February 2003, our parent, Noric III, was
obligated to pay approximately $41 million under this provision, and on February
7, 2003, we declared and paid a $41 million cash dividend to our parent. This
provision will continue until the amounts outstanding under the financing
arrangement have been repaid. As of December 31, 2002, the total amount
outstanding on the Clydesdale arrangement was approximately $950 million.

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

  CAPITAL EXPENDITURES

     Our capital expenditures, including our investments in unconsolidated
affiliates, during the periods indicated are listed below:

<Table>
<Caption>
                                                               YEAR ENDED
                                                              DECEMBER 31,
                                                              -------------
                                                              2002    2001
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
Maintenance.................................................  $ 57    $ 36
Expansion/Other.............................................    91     123
                                                              ----    ----
     Total..................................................  $148    $159
                                                              ====    ====
</Table>

     Under our current plan, we expect to spend between approximately $40
million and $50 million in each of the next three years for capital expenditures
to maintain the integrity of our pipeline and ensure the reliable delivery of
natural gas to our customers. In addition, we have budgeted to spend between
approximately $5 million and $25 million in each of the next three years to
expand the capacity of our system for long-term contracts. We expect to fund our
maintenance and expansion capital expenditures through a combination of
internally generated funds and external financing.

  DEBT

     For a discussion of our debt obligations, See Item 8, Financial Statements
and Supplementary Data, Note 7, which is incorporated herein by reference.

                         COMMITMENTS AND CONTINGENCIES

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

            NEW ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

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

ACCOUNTING FOR COSTS ASSOCIATED WITH EXIT OR DISPOSAL ACTIVITIES

     In July 2002, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounts Standards (SFAS) No. 146, Accounting for Costs
Associated with Exit or Disposal Activities. This statement will require us to
recognize costs associated with exit or disposal activities when they are
incurred rather than when we commit to an exit or disposal plan. Examples of
costs covered by this guidance include

                                        9
<PAGE>

lease termination costs, employee severance costs associated with a
restructuring, discontinued operations, plant closings or other exit or disposal
activities. This statement is effective for fiscal years beginning after
December 31, 2002, and will impact any exit or disposal activities we initiate
after January 1, 2003.

ACCOUNTING FOR GUARANTEES

     In November 2002, the FASB issued FASB Interpretation (FIN) No. 45,
Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others. This interpretation requires that
companies record a liability for all guarantees issued after January 31, 2003,
including financial, performance, and fair value guarantees. This liability is
recorded at its fair value upon issuance, and does not affect any existing
guarantees issued before December 31, 2002. While we do not believe there will
be any initial impact of adopting this Standard, it will impact any guarantees
we issue in the future.

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

     This report contains or incorporates by reference forward-looking
statements within the meaning of the Private Securities Litigation Reform Act of
1995. Where any forward-looking statement includes a statement of the
assumptions or bases underlying the forward-looking statement, we caution that,
while we believe these assumptions or bases to be reasonable and in good faith,
assumed facts or bases almost always vary from the actual results, and the
differences between assumed facts or bases and actual results can be material,
depending upon the circumstances. Where, in any forward-looking statement, we or
our management express an expectation or belief as to future results, that
expectation or belief is expressed in good faith and is believed to have a
reasonable basis. We cannot assure you, however, that the statement of
expectation or belief will result or be achieved or accomplished. The words
"believe," "expect," "estimate," "anticipate," "plan," "budget" 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.

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

                         RISKS RELATED TO OUR BUSINESS

OUR SUCCESS DEPENDS ON FACTORS BEYOND OUR CONTROL.

     Our business is the transportation, storage, processing and gathering of
natural gas for third parties. As a result, the volume of natural gas involved
in these activities depends on the actions of those third parties and is beyond
our control. Further, the following factors, most of which are beyond our
control, may unfavorably impact our ability to maintain or increase current
service volumes and rates, to renegotiate existing contracts as they expire, or
to remarket unsubscribed capacity:

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

     - price competition;

     - drilling activity and supply availability;

     - expiration and/or turn back of significant contracts;

     - service area competition;

     - changes in regulation and actions of regulatory bodies;
                                        10
<PAGE>

     - credit risk of customer base;

     - increased cost of capital; and

     - natural gas and liquids prices.

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

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

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

     - the proposed construction by other companies of additional pipeline
       capacity in markets served by us;

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

     - reduced demand and market conditions;

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

     - regulatory actions.

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

WE FACE COMPETITION THAT COULD ADVERSELY AFFECT OUR OPERATING RESULTS.

     Our competitors include other pipeline companies, as well as participants
in other industries supplying and transporting alternative fuels. If we are
unable to compete effectively, our future profitability may be negatively
impacted.

FLUCTUATIONS IN ENERGY COMMODITY PRICES COULD ADVERSELY AFFECT OUR BUSINESS.

     Revenues generated by our contracts depend on volumes and rates, both of
which can be affected by the prices of natural gas. Increased natural gas prices
could result in loss of load from our customers, such as power companies not
dispatching gas fired power plants, industrial plant shutdown or load loss to
competitive fuels and local distribution companies' loss of customer base due to
conversion from natural gas. The success of our operations is subject to
continued development of additional oil and natural gas reserves in the vicinity
of our facilities and our ability to access additional suppliers from
interconnecting pipelines to offset the natural decline from existing wells
connected to our systems. A decline in energy prices could precipitate a
decrease in these development activities and could cause a decrease in the
volume of reserves available for transmission or storage on our system.
Fluctuations in energy prices are caused by a number of factors, including:

     - regional, domestic and international supply and demand;

     - availability and adequacy of transportation facilities;

     - energy legislation;

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

     - abundance of supplies of alternative energy sources; and

     - political unrest among oil-producing countries.

                                        11
<PAGE>

THE AGENCIES THAT REGULATE US AND OUR CUSTOMERS AFFECT OUR PROFITABILITY.

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

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

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

     Our operations are subject to various environmental laws and regulations.
These laws and regulations obligate us to install and maintain pollution
controls and to clean up various sites at which regulated materials may have
been disposed of or released. We are also party to legal proceedings involving
environmental matters pending in various courts and agencies.

     It is not possible for us to estimate reliably the amount and timing of all
future expenditures related to environmental matters because of:

     - the uncertainties in estimating clean up costs;

     - the discovery of new sites or information;

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

     - the nature of environmental laws and regulations; and

     - the possible introduction of future environmental laws and regulations.

     Although we believe we have established appropriate reserves for
liabilities, including clean up costs, we could be required to set aside
additional reserves in the future due to these uncertainties. For additional
information, see Part II, Item 8, Financial Statements and Supplementary Data,
Note 8.

OUR OPERATIONS ARE SUBJECT TO OPERATIONAL HAZARDS AND UNINSURED RISKS.

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

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

ONE CUSTOMER CONTRACTS FOR A SUBSTANTIAL PORTION OF OUR FIRM TRANSPORTATION
CAPACITY.

     At December 31, 2002, contracts with Public Service Company of Colorado
represented approximately 50% of our firm transportation capacity. For
additional information, see Part I, Item 1, Business -- Markets and Competition
and Part II, Item 8, Financial Statements and Supplementary Data, Note 12. The
loss of this customer or a decline in its credit-worthiness could adversely
affect our results of operations, financial position and cash flow.

                                        12
<PAGE>

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

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

                 RISKS RELATED TO OUR AFFILIATION WITH EL PASO

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

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

     Due to our relationship with El Paso, adverse developments or announcements
concerning El Paso could adversely affect our financial condition, even if we
have not suffered any similar development. The outstanding senior unsecured
indebtedness of El Paso has been downgraded to below investment grade, currently
rated Caa1 by Moody's and B by Standard & Poor's (with a negative outlook at
both agencies), which in turn resulted in a similar downgrading of our
outstanding senior unsecured indebtedness to B1 by Moody's and B+ by Standard &
Poor's (with a negative outlook at both agencies). These downgrades will
increase our cost of capital and collateral requirements, and could impede our
access to capital markets. As a result of these recent downgrades, El Paso has
realized substantial demands on its liquidity, which demands have included:

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

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

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

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

     Pursuant to El Paso's cash management program, surplus cash is made
available to El Paso in exchange for an affiliated receivable. In addition, we
conduct commercial transactions with some of our affiliates. As of December 31,
2002, we have net receivables of approximately $496 million from El Paso and its
affiliates. El Paso provides cash management and other corporate services for
us. As a result of the downgrades discussed above, we are currently unable to
participate in El Paso's cash management program. If El Paso is unable to meet
its liquidity needs, there can be no assurance that our affiliates would pay
their obligations to us. However, we might still be required to satisfy
affiliated company payables. Our inability to recover any intercompany
receivables owed to us could adversely affect our ability to repay our
outstanding indebtedness.

                                        13
<PAGE>

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

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

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

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

     On March 20, 2003, El Paso entered into an agreement in principle (the
Western Energy Settlement) with various public and private claimants, including
the states of California, Washington, Oregon, and Nevada, to resolve the
principal litigation, claims, and regulatory proceedings against El Paso and its
subsidiaries relating to the sale or delivery of natural gas and electricity
from September 1996 to the date of the Western Energy Settlement. A more
detailed description of the Western Energy Settlement can be found in El Paso's
reports filed with the SEC. If El Paso is unable to negotiate definitive
settlement agreements, or if the settlement is not approved by the courts or the
FERC, the proceedings and litigation will continue.

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

     Another action was filed against El Paso in December 2002, on behalf of
participants in El Paso's 401(k) plan.

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

                                        14
<PAGE>

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

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

WE ARE A WHOLLY OWNED SUBSIDIARY OF NORIC HOLDINGS III L.L.C., AN INDIRECT
SUBSIDIARY OF EL PASO.

     El Paso has substantial control over:

     - our payment of dividends;

     - decisions on our financings and our capital raising activities;

     - mergers or other business combinations;

     - our acquisitions or dispositions of assets; and

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

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

                      RISKS RELATED TO OUR LONG-TERM DEBT

SOME OF OUR LONG-TERM DEBT IS SUBJECT TO CROSS-ACCELERATION PROVISIONS.

     It is an event of default in the indentures governing an issue of our
long-term debt if we fail to pay principal or interest beyond a stated grace
period on any of our other indebtedness with an outstanding principal amount
that exceeds $5 million, and such indebtedness could be accelerated as a result
of such missed payment, or if we otherwise default in compliance with the terms
of any such indebtedness, and the default results in the acceleration of such
indebtedness. If this were to occur, this issue of long-term debt would be
subject to possible acceleration, and we may not be able to repay such long-term
debt upon such acceleration.

                                        15
<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 and the fair value
of those securities. As of December 31, 2002, the fair values of our long-term
debt securities have been estimated based on quoted market prices for the same
or similar issues.

<Table>
<Caption>
                                                         DECEMBER 31, 2002
                                     ---------------------------------------------------------     DECEMBER 31,
                                       EXPECTED FISCAL YEAR OF MATURITY OF CARRYING AMOUNTS            2001
                                     ---------------------------------------------------------   ----------------
                                                                                         FAIR    CARRYING   FAIR
                                     2003-2004   2005   2006-2007   THEREAFTER   TOTAL   VALUE   AMOUNTS    VALUE
                                     ---------   ----   ---------   ----------   -----   -----   --------   -----
                                                                    (IN MILLIONS)
<S>                                  <C>         <C>    <C>         <C>          <C>     <C>     <C>        <C>
LIABILITIES:
  Long-term debt, including current
     portion -- fixed rate.........    $ --      $180     $ --         $100      $280    $250      $280     $306
     Average interest rate.........              10.1%                  6.9%
</Table>

                                        16
<PAGE>

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                        COLORADO INTERSTATE GAS COMPANY

                       CONSOLIDATED STATEMENTS OF INCOME
                                 (IN MILLIONS)

<Table>
<Caption>
                                                              YEAR ENDED DECEMBER 31,
                                                              ------------------------
                                                               2002     2001     2000
                                                              ------   ------   ------
<S>                                                           <C>      <C>      <C>
Operating revenues..........................................   $383     $376     $288
                                                               ----     ----     ----
Operating expenses
  Operation and maintenance.................................    198      225      119
  Merger-related costs......................................     --       31       --
  Depreciation, depletion and amortization..................     24       20       20
  Taxes, other than income taxes............................      7       10       12
                                                               ----     ----     ----
                                                                229      286      151
                                                               ----     ----     ----
Operating income............................................    154       90      137
Net gain on sale of assets..................................     26       --       --
Affiliated dividend income..................................     14        3       --
Other income................................................     --       --        3
Interest and debt expense...................................    (23)     (23)     (24)
Affiliated interest income..................................      4       11       22
                                                               ----     ----     ----
Income before income taxes..................................    175       81      138
Income taxes................................................     59       26       50
                                                               ----     ----     ----
Income from continuing operations...........................    116       55       88
Discontinued operations, net of income taxes................     41       38       26
                                                               ----     ----     ----
Net income..................................................    157       93      114
Other comprehensive income (loss)...........................     (3)       3       --
                                                               ----     ----     ----
Comprehensive income........................................   $154     $ 96     $114
                                                               ====     ====     ====
</Table>

                            See accompanying notes.

                                        17
<PAGE>

                        COLORADO INTERSTATE GAS COMPANY

                          CONSOLIDATED BALANCE SHEETS
                      (IN MILLIONS, EXCEPT SHARE AMOUNTS)

<Table>
<Caption>
                                                               DECEMBER 31,
                                                              ---------------
                                                               2002     2001
                                                              ------   ------
<S>                                                           <C>      <C>
                                   ASSETS

Current assets
  Cash and cash equivalents.................................  $   11   $    1
  Accounts and notes receivable
    Customer, net of allowance of $3 for 2002 and less than
      $1 for 2001...........................................      50       45
    Affiliates..............................................      61      285
    Other...................................................       1       --
  Materials and supplies....................................       5        5
  Assets of discontinued operations.........................      22       56
  Assets held for sale......................................      13       --
  Deferred income taxes.....................................      13       11
  Other.....................................................       1        4
                                                              ------   ------
         Total current assets...............................     177      407
                                                              ------   ------
Property, plant and equipment, at cost
  Pipeline..................................................   1,175    1,089
  Gathering and processing systems..........................      98      151
  Other.....................................................      --      164
                                                              ------   ------
                                                               1,273    1,404
  Less accumulated depreciation, depletion and
    amortization............................................     487      675
                                                              ------   ------
         Total property, plant and equipment, net...........     786      729
                                                              ------   ------
Other assets
  Note receivable from affiliate............................     444       --
  Investments in unconsolidated affiliates..................      --       29
  Assets of discontinued operations.........................      --       89
  Other.....................................................       3        6
                                                              ------   ------
                                                                 447      124
                                                              ------   ------
         Total assets.......................................  $1,410   $1,260
                                                              ======   ======

                    LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities
  Accounts payable
    Trade...................................................  $   26   $   31
    Affiliates..............................................       9       51
    Other...................................................      12       28
  Taxes payable.............................................      89       49
  Accrued liabilities.......................................      18       24
  Liabilities of discontinued operations....................      --        8
  Contractual deposits......................................       8       --
  Other.....................................................       2        3
                                                              ------   ------
         Total current liabilities..........................     164      194
                                                              ------   ------
Long-term debt..............................................     280      280
                                                              ------   ------
Other liabilities
  Deferred income taxes.....................................     144      109
  Liabilities of discontinued operations....................      --       12
  Other.....................................................      32       29
                                                              ------   ------
                                                                 176      150
                                                              ------   ------
Commitments and contingencies

Stockholder's equity
  Common stock, par value $1 per share; 1,000 shares
    authorized and issued at December 31, 2002; and no par
    value; 10,000 shares authorized, 10 shares issued and
    outstanding at stated value at December 31, 2001........      --       28
  Additional paid-in capital................................      48       20
  Retained earnings.........................................     742      585
  Accumulated other comprehensive income....................      --        3
                                                              ------   ------
         Total stockholder's equity.........................     790      636
                                                              ------   ------
         Total liabilities and stockholder's equity.........  $1,410   $1,260
                                                              ======   ======
</Table>

                            See accompanying notes.
                                        18
<PAGE>

                        COLORADO INTERSTATE GAS COMPANY

                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                                 (IN MILLIONS)

<Table>
<Caption>
                                                              YEAR ENDED DECEMBER 31,
                                                              -----------------------
                                                               2002     2001    2000
                                                              ------   ------   -----
<S>                                                           <C>      <C>      <C>
Cash flows from operating activities
  Net income................................................  $ 157    $  93    $114
     Less income from discontinued operations, net of income
      taxes.................................................     41       38      26
                                                              -----    -----    ----
  Net income from continuing operations.....................    116       55      88
  Adjustments to reconcile net income from continuing
     operations to net cash from operating activities
     Depreciation, depletion and amortization...............     24       20      20
     Deferred income tax expense............................     32       11      23
     Non-cash portion of merger-related costs...............     --       17      --
     Net gain on sale of assets.............................    (26)      --      --
     Other non-cash income items............................     (4)       5      --
     Working capital changes, net of non-cash transactions
       Accounts receivable..................................      8      (28)     13
       Accounts payable.....................................    (52)       6     (34)
       Taxes payable........................................     40       26      (7)
       Other working capital changes
          Assets............................................     17      (16)     --
          Liabilities.......................................      7       44      (2)
     Non-working capital changes
       Assets...............................................     13        5       1
       Liabilities..........................................     (8)       5      --
                                                              -----    -----    ----
     Cash provided by continuing operations.................    167      150     102
     Cash provided by discontinued operations...............     36       10      34
                                                              -----    -----    ----
          Net cash provided by operating activities.........    203      160     136
                                                              -----    -----    ----
Cash flows from investing activities
  Additions to property, plant and equipment................   (135)    (159)    (41)
  Additions to investments..................................    (13)      --      --
  Return of capital from investments........................     --       33      --
  Net proceeds from the sale of assets......................     35        2      --
  Net proceeds from the sale of CIG Exploration Inc.........     49       --      --
  Net change in affiliated advances receivable..............   (237)      99     (34)
  Other.....................................................     (1)      --       2
                                                              -----    -----    ----
     Cash used in continuing operations.....................   (302)     (25)    (73)
     Cash provided by (used in) discontinued operations.....    109      (15)    (22)
                                                              -----    -----    ----
          Net cash used in investing activities.............   (193)     (40)    (95)
                                                              -----    -----    ----
Cash flows from financing activities
  Contributions from (distributions to) discontinued
     operations.............................................    145       (5)     12
  Net change in notes to affiliate..........................     --       --      (2)
  Dividends paid............................................     --     (120)    (39)
                                                              -----    -----    ----
     Net cash provided by (used in) continuing operations...    145     (125)    (29)
     Cash provided by (used in) discontinued operations.....   (145)       5     (12)
                                                              -----    -----    ----
          Net cash used in financing activities.............     --     (120)    (41)
Increase in cash and cash equivalents.......................     10       --      --
  Less change in cash and cash equivalents related to
     discontinued operations................................     --       --      --
                                                              -----    -----    ----
  Increase in cash and cash equivalents from continuing
     operations.............................................     10       --      --
Cash and cash equivalents
  Beginning of period.......................................      1        1       1
                                                              -----    -----    ----
  End of period.............................................  $  11    $   1    $  1
                                                              =====    =====    ====
</Table>

                            See accompanying notes.

                                        19
<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, 2000.................     10     $ 28       $19        $ 537          $--            $ 584
  Net income....................                                    114                           114
  Cash dividend.................                                    (39)                          (39)
                                  -----     ----       ---        -----          ---            -----
December 31, 2000...............     10       28        19          612           --              659
  Net income....................                                     93                            93
  Allocated tax benefit of El
     Paso equity plans..........                         1                                          1
  Other comprehensive income,
     net of $1 in taxes.........                                                   3                3
  Cash dividend.................                                   (120)                         (120)
                                  -----     ----       ---        -----          ---            -----
December 31, 2001...............     10       28        20          585            3              636
  Net income....................                                    157                           157
  Other comprehensive loss, net
     of $1 in taxes.............                                                  (3)              (3)
  Change in par value and shares
     of common stock............    990      (28)       28                                         --
                                  -----     ----       ---        -----          ---            -----
December 31, 2002...............  1,000     $ --       $48        $ 742          $--            $ 790
                                  =====     ====       ===        =====          ===            =====
</Table>

                            See accompanying notes.

                                        20
<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.

     Our natural gas pipeline is subject to the jurisdiction of the FERC in
accordance with the Natural Gas Act of 1938 and Natural Gas Policy Act of 1978.
Effective November 1, 1996 we discontinued the application of regulatory
accounting principles under SFAS No. 71, Accounting for the Effects of Certain
Types of Regulation. SFAS No. 71 provides that rate regulated enterprises
account for and report assets and liabilities consistent with the economic
effect of the way in which regulators establish rates, if the rates are designed
to recover the costs of providing the regulated service and if the competitive
environment makes it reasonable to assume that such rates can be charged and
collected. We regularly evaluate the appropriateness of reinstating the
application of SFAS No. 71.

  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.

                                        21
<PAGE>

  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 the
end of year actual or appropriate market index price. 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.

  Property, Plant and Equipment

     Our property, plant and equipment is recorded at its original cost of
construction or, upon acquisition, at the fair value of the assets acquired. We
capitalize direct costs, such as labor and materials and indirect costs, such as
interest and overhead. 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        50                2%
Gathering and processing systems.......................  Straight-line       1-40        3% to 20%
Transportation equipment...............................  Straight-line       1-5        10% to 33%
Buildings and improvements.............................  Straight-line       1-40         3% to 8%
Office and miscellaneous equipment.....................  Straight-line       1-15        3% 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 as a gain or loss to income.

     At December 31, 2002 and 2001, we had approximately $71 million and $23
million of construction work in progress included in our property, plant and
equipment.

     We capitalize a carrying cost on funds invested in our construction of
long-lived assets. The capitalized interest is calculated based on our average
cost of debt. Debt amounts capitalized during the years ended December 31, 2002,
2001 and 2000, were $3 million, $2 million and $1 million. These amounts are
included as a reduction of interest expense in our income statement.

  Asset Impairments

     We apply the provisions of SFAS No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, to account for asset impairments. Under this
standard, we evaluate an asset for impairment when events or circumstances
indicate that a long-lived asset's carrying value may not be recovered. These
events include market declines, changes in the manner in which we intend to use
an asset or decisions to sell an asset and adverse changes in the legal or
business environment such as adverse actions by regulators. At the time we
decide to exit an activity or sell a long-lived asset or group of assets, we
adjust the carrying value of those assets downward, if necessary, to the
estimated sales price, less costs to sell. We also classify these assets as
either held for sale or as discontinued operations, depending on whether they
have independently determinable cash flows. We applied SFAS No. 144 in
accounting for our sale of gathering facilities located in Wyoming, which met
all of the requirements to be treated as an asset held for sale in the fourth
quarter of 2002. We also applied SFAS No. 144 in accounting for our Panhandle
Field of Texas, southeast Kansas and the Oklahoma Panhandle natural gas and oil
operations and a related gas gathering system, which met all of the requirements
to be treated as discontinued operations in 2002. See Note 2 for further
information.

                                        22
<PAGE>

  Revenue Recognition

     Our revenues consist primarily of demand and throughput-based
transportation, storage and natural gas gathering and processing services. We
recognize demand revenues on firm contracted capacity and storage monthly over
the contract period, regardless of the amount of capacity that is actually used.
For throughput-based services and for gathering and processing services, we
record revenues when we complete the delivery of natural gas to the agreed upon
delivery point. Revenues on sales of natural gas and related products are
recognized when physical deliveries of commodities are made at the agreed upon
delivery point. Revenues in all services are generally based on the thermal
quantity of gas delivered or subscribed at a price specified in the contract or
tariff. Our pipeline is subject to FERC regulations and, as a result, revenues
we collect may be refunded in a final order of a pending rate proceeding or as a
result of a rate settlement. We establish reserves for these potential refunds.

  Environmental Costs and Other Contingencies

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

  Income Taxes

     We report current income taxes based on our taxable income and we provide
for deferred income taxes to reflect estimated future tax payments or receipts.
Deferred taxes represent the tax impacts of differences between the financial
statement and tax bases of assets and liabilities and carryovers at each year
end. We account for tax credits under the flow-through method, which reduces the
provision for income taxes in the year the tax credits first become available.
We reduce deferred tax assets by a valuation allowance when, based on our
estimates, it is more likely than not that a portion of those assets will not be
realized in a future period. The estimates utilized in 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 accrual policy to record both regular and
alternative minimum taxes for companies included in its consolidated federal
income tax return. The policy provides, among other things, that (i) each
company in a taxable income position will accrue a current expense equivalent to
its federal income tax, and (ii) each company in a tax loss position will accrue
a benefit to the extent its deductions, including general business credits, can
be utilized in the consolidated return. El Paso pays all federal income taxes
directly to the IRS and, under a separate tax billing agreement, El Paso may
bill or refund its subsidiaries for their portion of these income tax payments.
Prior to 2002, we had a tax sharing agreement with El Paso CGP which had similar
provisions.

                                        23
<PAGE>

  New Accounting Pronouncements Issued But Not Yet Adopted

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

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

  Accounting for Guarantees. In November 2002, the FASB issued FIN No. 45,
  Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others. This interpretation requires that
companies record a liability for all guarantees issued after January 31, 2003,
including financial, performance, and fair value guarantees. This liability is
recorded at its fair value upon issuance, and does not affect any existing
guarantees issued before December 31, 2002. While we do not believe that there
will be any initial impact of adopting this standard, it will impact any
guarantees we issue in the future.

2. DISCONTINUED OPERATIONS AND DIVESTITURES

  Discontinued Operations

     In April 2002, we executed an agreement to sell to Pioneer all of our
interests in natural gas and oil production properties and related contracts
located in Texas, Kansas and Oklahoma. The sale was completed on July 1, 2002,
and as part of the sale, we assigned all our rights and obligations under the
Amarillo "B" contract to Pioneer. These properties were previously included in
our Pipeline segment. Net proceeds from the sale were approximately $112
million, and we recognized a gain in the third quarter of 2002 of approximately
$23 million, net of an $8 million reserve for environmental contingencies and
$13 million of income taxes. We also executed an agreement to sell to Pioneer a
federally regulated natural gas gathering system located in the Panhandle Field
of Texas for its approximate net book value of $19 million. We have received
proceeds from Pioneer related to this transaction, which we have recorded as
other liabilities pending completion of the sale. We received a certificate to
abandon the gathering facilities from the FERC on December 26, 2002 and
completed the sale on February 28, 2003.

     These assets and the related natural gas gathering system were historically
reported in our Pipeline segment, but have been reclassified as discontinued
operations in our financial statements for all periods presented. In addition,
we classified all of these assets and liabilities as other current assets and
liabilities since we will have sold them within a twelve-month period. The
summarized financial results of our discontinued operations are as follows:

<Table>
<Caption>
                                                                 DECEMBER 31,
                                                              ------------------
                                                              2002   2001   2000
                                                              ----   ----   ----
                                                                (IN MILLIONS)
<S>                                                           <C>    <C>    <C>
Operating Results:
  Revenues..................................................  $ 50   $121   $100
  Costs and expenses........................................   (21)   (61)   (59)
                                                              ----   ----   ----
  Operating income..........................................    29     60     41
  Gain on sale of assets(1).................................    36     --     --
                                                              ----   ----   ----
  Income before income taxes................................    65     60     41
  Income taxes..............................................   (24)   (22)   (15)
                                                              ----   ----   ----
  Income from discontinued operations, net of income
     taxes..................................................  $ 41   $ 38   $ 26
                                                              ====   ====   ====
</Table>

---------------
(1) Net of an $8 million reserve for environmental contingencies.

                                        24
<PAGE>

<Table>
<Caption>
                                                               2002    2001
                                                              ------   -----
                                                              (IN MILLIONS)
<S>                                                           <C>      <C>
Financial Position Data:
  Assets of discontinued operations
     Accounts receivable....................................  $  --    $ 51
     Property, plant and equipment, net.....................     19      89
     Other..................................................      3       5
                                                              -----    ----
          Total assets......................................  $  22    $145
                                                              =====    ====
  Liabilities of discontinued operations
     Accounts payable and other current liabilities.........  $  --    $  8
     Deferred income taxes..................................     --      12
                                                              -----    ----
          Total liabilities.................................  $  --    $ 20
                                                              =====    ====
</Table>

 Divestitures

     During March 2002, we sold natural gas and oil production properties
located in south Texas, to El Paso CGP. Proceeds from this sale were
approximately $2 million. We did not recognize a gain or loss on the properties
sold.

     During November 2002, we sold CIG Exploration, Inc., a consolidated
subsidiary that was previously reported as part of the Other segment, to CIGE
Holdco, Inc., an affiliated company. We received gross proceeds from this sale
of $75 million, which was based on the net book value of the company (since the
sale occurred between entities under common control). In conjunction with this
sale, we paid off our $26 million note payable to CIG Exploration Inc. We did
not recognize a gain or loss on the sale.

     In December 2002, we sold the Natural Buttes gas gathering facilities to
Westport Resources Corporation. Net proceeds from this sale were approximately
$39 million, and we recognized a gain of approximately $25 million.

     In December 2002, we received approval to sell several of our small
gathering systems located in Wyoming. As of December 31, 2002, these assets were
reclassified as held for sale in our balance sheet, and we stopped depreciating
them. The total assets being sold include net property, plant and equipment of
approximately $13 million. In January 2003, we sold these assets to Western Gas
Resources, Inc. Net proceeds from this sale were approximately $14 million, and
we will recognize a gain of approximately $1 million.

     We have received appropriate management approval to sell our remaining
assets in the Mid-Continent region. These assets primarily include our
Greenwood, Hugoton, Keyes and Mocane natural gas gathering systems, our
processing plant and our processing arrangements at three additional processing
plants. We expect this sale to close by the end of 2003.

3. 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 in January 2001.
These charges include employee costs of $13 million which 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, costs for pension and post-retirement benefits
settled and curtailed under existing benefit plans. Following the merger,
approximately 180 full-time positions were eliminated through a combination of
early retirement and terminations. The pension and post-retirement benefits were
accrued on the merger date and will be paid over the applicable benefit periods
of the terminated and retired employees. All other employee costs were expensed
as incurred and were paid in the first and second quarters of 2001. Also
included in merger-related costs were $18 million, primarily associated with a
$7 million write-off related to the valuation of natural gas imbalances to
conform our imbalance valuation methods to El Paso's, and $9 million related to
a disputed gas

                                        25
<PAGE>

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

4. INCOME TAXES

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

<Table>
<Caption>
                                                              2002   2001   2000
                                                              ----   ----   ----
                                                                (IN MILLIONS)
<S>                                                           <C>    <C>    <C>
Current
  Federal...................................................  $24    $13    $26
  State.....................................................    3      2      1
                                                              ---    ---    ---
                                                               27     15     27
                                                              ---    ---    ---
Deferred
  Federal...................................................   29     12     21
  State.....................................................    3     (1)     2
                                                              ---    ---    ---
                                                               32     11     23
                                                              ---    ---    ---
          Total income tax expense from continuing
            operations......................................  $59    $26    $50
                                                              ===    ===    ===
</Table>

     Our income tax expense from continuing operations 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>
                                                              2002   2001   2000
                                                              ----   ----   ----
                                                                (IN MILLIONS)
<S>                                                           <C>    <C>    <C>
Tax expense at the statutory federal rate of 35%............  $61    $28    $48
Items creating rate differences:
  State income tax, net of federal income tax benefit.......    4      1      2
  Affiliated dividend income................................   (5)    (1)    --
  Other.....................................................   (1)    (2)    --
                                                              ---    ---    ---
Income tax expense from continuing operations...............  $59    $26    $50
                                                              ===    ===    ===
Effective tax rate..........................................   34%    32%    36%
                                                              ===    ===    ===
</Table>

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

<Table>
<Caption>
                                                              2002    2001
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
Deferred tax liabilities
  Property, plant and equipment.............................  $142    $126
  Other.....................................................    11      15
                                                              ----    ----
          Total deferred tax liability......................   153     141
                                                              ----    ----
Deferred tax assets
  Reserve for rate refund and contested claims..............     2      10
  Employee benefits and deferred compensation obligations...     7       7
  Other.....................................................    13      26
                                                              ----    ----
          Total deferred tax asset..........................    22      43
                                                              ----    ----
Net deferred tax liability..................................  $131    $ 98
                                                              ====    ====
</Table>

                                        26
<PAGE>

     Under El Paso's tax accrual 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.

5. FINANCIAL INSTRUMENTS

  Fair Value of Financial Instruments

     As of December 31, 2002 and 2001, 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. The carrying amounts and estimated fair values of our financial
instruments are as follows at December 31:

<Table>
<Caption>
                                                               2002                     2001
                                                       ---------------------    ---------------------
                                                       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(1)....    $280        $250         $280        $306
Other financial instruments:
     Non-Trading instruments
       Commodity swap contracts(2)...................    $ --        $ --         $  3        $  3
</Table>

---------------
(1) We estimated the fair value of debt with fixed interest rates based on
    quoted market prices for the same or similar issues.

(2) On January 1, 2001, we adopted SFAS No. 133. Under SFAS No. 133, all
    derivative instruments are recorded at their fair value in our financial
    statements. During 2001, we maintained cash flow hedges on natural gas sales
    associated with production activities that were sold during 2002. As a
    result, we had no hedges as of December 31, 2002. See Note 6 below.

6. ACCUMULATED OTHER COMPREHENSIVE INCOME

     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. As a result of the sale of
most of our pipeline segment's natural gas and oil properties, in June 2002, we
recognized a $3 million reduction in comprehensive income on derivative
positions that no longer qualified as cash flow hedges under SFAS No. 133,
Accounting for Derivative Instruments and Hedging Activities. We terminated all
of our derivative positions in 2002, and are no longer involved in hedging
activities. For the years ended December 31, 2002 and 2001, no ineffectiveness
was recorded in earnings on our cash flow hedges.

7. LONG-TERM DEBT

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

<Table>
<Caption>
                                                              2002    2001
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
10% Senior Debentures, due 2005(1)..........................  $180    $180
6.85% Senior Debentures, due 2037...........................   100     100
                                                              ----    ----
          Long-term debt....................................  $280    $280
                                                              ====    ====
</Table>

---------------
(1) Contains cross-acceleration provisions which, if triggered, could result in
    the acceleration of our long-term debt.

                                        27
<PAGE>

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

<Table>
<Caption>
                                                              (IN MILLIONS)
<S>                                                           <C>
2003........................................................      $ --
2004........................................................        --
2005........................................................       180
2006........................................................        --
2007........................................................        --
Thereafter..................................................       100
                                                                  ----
          Total long-term debt..............................      $280
                                                                  ====
</Table>

  Other Financing Arrangement

     During 2000, El Paso formed a series of companies that it refers to as
Clydesdale. Clydesdale was formed to provide financing to invest in various
capital projects and other assets. The outstanding amounts under this financing
transaction of approximately $950 million are collateralized by us and other El
Paso affiliates.

     In a series of credit rating agency actions in late 2002 and early 2003,
and contemporaneously with the downgrades of the senior unsecured indebtedness
of El Paso, our senior unsecured indebtedness was downgraded below investment
grade and is currently rated B1 by Moody's and B+ by Standard & Poor's.

     These downgrades prevent us from providing our excess cash to El Paso under
its cash management program. Each quarter, our parent company is required to pay
from these excess funds a specified amount (based on our cash-based earnings) to
retire the amounts outstanding under the Clydesdale financing arrangement. In
February 2003, our parent, Noric III, was obligated to pay approximately $41
million under this provision, and on February 7, 2003, we declared and paid a
$41 million cash dividend to our parent. This provision will continue until the
amounts outstanding under the financing have been repaid. As of December 31,
2002, the total amount outstanding on the Clydesdale financing arrangement was
approximately $950 million.

8. COMMITMENTS AND CONTINGENCIES

  Legal Proceedings

     Grynberg.  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 underreport the heating value as well as the volumes of the natural gas
produced from federal and Native American lands, which deprived the U.S.
Government of royalties. The plaintiff in this case seeks royalties that he
contends the government should have received had the volume and heating value of
natural gas produced from royalty properties been differently measured,
analyzed, calculated and reported, together with interest, treble damages, civil
penalties, expenses and future injunctive relief to require the defendants to
adopt allegedly appropriate gas measurement practices. No monetary relief has
been specified in this case. These matters have been consolidated for pretrial
purposes (In re: Natural Gas Royalties Qui Tam Litigation, U.S. District Court
for the District of Wyoming, filed June 1997). In May 2001, the court denied the
defendants' motion to dismiss. Discovery is proceeding. Our costs and legal
exposure related to these lawsuits and claims are not currently determinable.

     Will Price (formerly Quinque).  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. Quinque has been dropped as a plaintiff and Will Price has been added.
This class action complaint alleges that the defendants mismeasured natural gas
volumes and heating content of natural gas on non-federal and non-Native
American lands. The plaintiff in this case seeks certification of a nationwide
class of natural gas working interest owners and natural gas royalty owners to
recover royalties that the plaintiff contends these owners should have received
had the volume and heating value of natural gas produced from their properties
been differently measured, analyzed, calculated and reported, together with

                                        28
<PAGE>

prejudgment and postjudgment interest, punitive damages, treble damages,
attorney's fees, costs and expenses, and future injunctive relief to require the
defendants to adopt allegedly appropriate gas measurement practices. No monetary
relief has been specified in this case. Plaintiff's motion for class
certification has been argued and we are awaiting a ruling. Our costs and legal
exposure related to this lawsuit and claims are not currently determinable.

     Cimarron County.  In January of 2003, our subsidiary, CIG Field Services
Company, was named a defendant in a suit titled Patty Hiner, As Duly Elected
County Assessor, The Board of County Commissioners for Cimarron County, Oklahoma
vs. CIG Field Services Company in Cimarron County District Court, alleging that
in 1999 our agents falsely represented the value of our property to the Cimarron
County Property Tax Assessor. The plaintiffs seek compensatory and punitive
damages. Our subsidiary is in the process of moving the case to the United
States District Court for the Western District of Oklahoma for trial.

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

     For each of our outstanding legal matters, we evaluate the merits of the
case, our exposure to the matter, possible legal or settlement strategies and
the likelihood of an unfavorable outcome. If we determine that an unfavorable
outcome is probable and can be estimated, we establish the necessary accruals.
As of December 31, 2002, we had approximately $2 million accrued for all
outstanding legal matters.

  Environmental Matters

     We are subject to federal, state and local laws and regulations governing
environmental quality and pollution control. These laws and regulations require
us to remove or remedy the effect on the environment of the disposal or release
of specified substances at current and former operating sites. As of December
31, 2002, we had accrued approximately $13 million for expected remediation
costs and associated onsite, offsite and groundwater technical studies, which we
anticipate incurring through 2027. The $8 million addition to our accrued
liability in 2002 is due to environmental contingencies identified during our
sale to Pioneer of our interests in natural gas and oil properties and related
contracts located in Texas, Kansas and Oklahoma. Below is a reconciliation of
our accrued liability as of December 31, 2001 to our accrued liability as of
December 31, 2002:

<Table>
<Caption>
                                                              2002    2001
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
Balance as of January 1.....................................   $ 7     $ 4
Additions/adjustments for remediation activities............     8      --
Payment for remediation activities..........................    (2)     --
Other.......................................................    --       3
                                                               ---     ---
Balance as of December 31...................................   $13     $ 7
                                                               ===     ===
</Table>

     In addition, we expect to make capital expenditures for environmental
matters of approximately $1 million in the aggregate for the years 2003 through
2007. 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 reserves are
adequate.

                                        29
<PAGE>

  Rates and Regulatory Matters

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

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

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

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

     Also on August 1, 2002, the FERC's Chief Accountant issued an Accounting
Release, which was effective immediately. The Accounting Release provides
guidance on how companies should account for money pool arrangements and the
types of documentation that should be maintained for these arrangements.
However, it did not address the proposed requirements that the FERC regulated
entity maintain a minimum proprietary capital balance of 30 percent and that the
entity and its parent have investment grade credit ratings. Requests for
rehearing were filed on August 30, 2002. The FERC has not yet acted on the
rehearing requests.

                                        30
<PAGE>

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

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

     While the outcome of our outstanding legal matters, environmental matters,
and rates and regulatory matters cannot be predicted with certainty, based on
current information and our existing accruals, we do not expect the ultimate
resolution of these matters to have a material adverse effect on our financial
position, operating results or cash flows. However, it is possible that new
information or future developments could require us to reassess our potential
exposure related to these matters. It is also possible that these matters could
impact our debt rating and the credit rating of our parent. Further, for
environmental matters, it is also possible that other developments, such as
increasingly strict environmental laws and regulations and claims for damages to
property, employees, other persons and the environment resulting from our
current or past operations, could result in substantial costs and liabilities in
the future. As new information for our outstanding legal matters, environmental
matters and rates and regulatory matters becomes available, or relevant
developments occur, we will review our accruals and make any appropriate
adjustments. The impact of these changes may have a material effect on our
results of operations, our financial position, and on our cash flows in the
period the event occurs.

  Capital Commitments

     At December 31, 2002, we had capital and investment commitments of $31
million primarily related to our ongoing capital 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 2003 to
2007 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. See a further discussion of transactions with
related parties in Note 14. Rental expense on our operating leases for the years
ended December 31, 2002, 2001 and 2000, was $3 million, $3 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 annual payments of $9 million per year for 2003 and $3 million per year
for 2004 through 2006, and $2 million in 2007. We expensed approximately $9
million for each of the three years ended December 31, 2002 pursuant to this
agreement.

9. COMMON STOCK

     On March 7, 2002, our Board of Directors approved and we filed an amended
and restated certificate of incorporation, changing our authorized shares of
stock to 1,000 shares of common stock, with a par value of
                                        31
<PAGE>

$1 per share. As a result, $28 million of common stock was reclassified to
additional paid-in capital during 2002. This action and the reclassification did
not impact our total stockholder's equity. As of December 31, 2001, we had
10,000 authorized shares and 10 shares issued and outstanding at stated value.

     During 2001 and 2000, we paid cash dividends to our parent of $120 million
and $39 million. No common stock dividends were declared or paid during 2002. In
February 2003, we declared and paid a $41 million dividend to our parent.

10. RETIREMENT BENEFITS

  Pension and Retirement Benefits

     El Paso maintains a pension plan to provide benefits as determined under a
cash balance formula covering substantially all of its U.S. employees, including
our employees. In addition, El Paso maintains a defined contribution plan
covering its U.S. employees, including our employees. Prior to May 1, 2002, El
Paso matched 75 percent of participant basic contributions up to 6 percent, with
matching contributions being made to the plan's stock fund, which participants
could diversify at any time. After May 1, 2002, the plan was amended to allow
for matching contributions to be invested in the same manner as that of
participant contributions. Effective March 1, 2003, El Paso suspended the
matching contribution. El Paso is responsible for benefits accrued under its
plans and allocates the related costs to its affiliates. See Note 14 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 cash balance
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.
Total charges 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 retired on or after June 30, 2001, continue to
receive limited postretirement life insurance benefits. Our postretirement
benefit plan costs are pre-funded to the extent these costs are recoverable
through rates.

                                        32
<PAGE>

     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.

     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 September 30:

<Table>
<Caption>
                                                              2002    2001
                                                              -----   -----
                                                              (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       1
  Plan amendment............................................    --      (2)
  Curtailment and special termination benefits..............    --       3
  Actuarial gain............................................    (2)     (2)
  Benefits paid.............................................    (2)     (1)
                                                               ---     ---
  Postretirement benefit obligation at end of period........   $13     $15
                                                               ===     ===
Change in plan assets
  Fair value of plan assets at beginning of period..........   $10     $10
  Employer contributions....................................     2       1
  Benefits paid.............................................    (2)     (1)
                                                               ---     ---
  Fair value of plan assets at end of period................   $10     $10
                                                               ===     ===
Reconciliation of funded status
  Funded status at end of period............................   $(3)    $(5)
  Fourth quarter contributions..............................     1       1
  Unrecognized actuarial gain...............................    (4)     (3)
                                                               ---     ---
  Accrued postretirement liability at December 31...........   $(6)    $(7)
                                                               ===     ===
</Table>

<Table>
<Caption>
                                                                   YEAR ENDED
                                                                  DECEMBER 31,
                                                              ---------------------
                                                              2002    2001    2000
                                                              -----   -----   -----
                                                                  (IN MILLIONS)
<S>                                                           <C>     <C>     <C>
Postretirement benefit costs include the following
  components
  Interest cost.............................................  $  1    $  1    $   1
  Amortization of transition obligation.....................    --      --        1
  Curtailment and special termination benefits..............    --       8       --
                                                              -----   -----   -----
  Net postretirement benefit cost...........................  $  1    $  9    $   2
                                                              =====   =====   =====
</Table>

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

<Table>
<Caption>
                                                              2002    2001
                                                              -----   -----
<S>                                                           <C>     <C>
Weighted average assumptions
  Discount rate.............................................  6.75%   7.25%
  Expected return on plan assets............................  7.50%   7.50%
</Table>

                                        33
<PAGE>

     Actuarial estimates for our postretirement benefits plans assumes a
weighted average annual rate of increase in the per capita costs of covered
health care benefits of 11.0 percent in 2002, gradually decreasing to 5.5
percent by the year 2008. Assumed health care cost trends have a significant
effect on the amounts reported for other postretirement benefit plans. 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.

11. SEGMENT INFORMATION

     Our Pipeline and Field Services segments are strategic business units that
provide a variety of services. They are managed separately as each business unit
requires different marketing strategies. During the second quarter, we
reclassified the majority of our natural gas and oil production activities from
our Pipeline segment to discontinued operations in our financial statements. All
periods were restated to reflect this change. We use EBIT to assess the
operating result and effectiveness of our business segments. We define EBIT as
operating income, adjusted for gains and losses on sales of assets and other
miscellaneous non-operating items. Items that are not included in this measure
are financing costs, including interest and debt expense, income taxes and
discontinued operations. We believe this measurement is useful to our investors
because it allows them to evaluate the effectiveness of our businesses and
operations and our investments from an operational perspective, exclusive of the
costs to finance these activities and exclusive of income taxes, neither of
which are directly relevant to the efficiency of those operations. This
measurement may not be comparable to measurements used by other companies and
should not be used as a substitute for net income or other performance measures
such as operating cash flow. The following are our segment results as of and for
the years ended December 31:

<Table>
<Caption>
                                                        YEAR ENDED DECEMBER 31, 2002
                                               -----------------------------------------------
                                               PIPELINE   FIELD SERVICES(1)   OTHER(2)   TOTAL
                                               --------   -----------------   --------   -----
                                                                (IN MILLIONS)
<S>                                            <C>        <C>                 <C>        <C>
Revenues from external customers.............    $247           $135            $ 1      $383
Intersegment revenues........................      --              1             (1)       --
Depreciation, depletion and amortization.....      21              3             --        24
Operating income.............................     140             14             --       154
Other income.................................       1             25             14        40
EBIT.........................................     141             39             14       194
Capital expenditures including investments in
  unconsolidated affiliates..................     130              6             12       148
</Table>

<Table>
<Caption>
                                                        YEAR ENDED DECEMBER 31, 2001
                                               -----------------------------------------------
                                               PIPELINE   FIELD SERVICES(1)   OTHER(2)   TOTAL
                                               --------   -----------------   --------   -----
                                                                (IN MILLIONS)
<S>                                            <C>        <C>                 <C>        <C>
Revenues from external customers.............    $245           $125            $ 6      $376
Intersegment revenues........................       1              1             (2)       --
Merger-related costs.........................      31             --             --        31
Depreciation, depletion and amortization.....      18              2             --        20
Operating income.............................      63             22              5        90
Other income.................................       3             --             --         3
EBIT.........................................      66             22              5        93
Capital expenditures including investments in
  unconsolidated affiliates..................     172              3             --       175
Total investments in unconsolidated
  affiliates.................................      --             --             29        29
</Table>

                                        34
<PAGE>

<Table>
<Caption>
                                                        YEAR ENDED DECEMBER 31, 2000
                                               -----------------------------------------------
                                               PIPELINE   FIELD SERVICES(1)   OTHER(2)   TOTAL
                                               --------   -----------------   --------   -----
                                                                (IN MILLIONS)
<S>                                            <C>        <C>                 <C>        <C>
Revenues from external customers.............    $238            $30            $20      $288
Depreciation, depletion and amortization.....      13              2              5        20
Operating income.............................     114             14              9       137
Other income (expense).......................       4             --             (1)        3
EBIT.........................................     118             14              8       140
Capital expenditures including investments in
  unconsolidated affiliates..................      58              3              2        63
Total investments in unconsolidated
  affiliates.................................      33             --             29        62
</Table>

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

(1) After the sale of our remaining assets in the Mid-Continent region, which is
    expected to close by the end of the second quarter of 2003, we will no
    longer have any operating assets in this segment.

(2) Includes consolidating eliminations of approximately $1 million, $2 million
    and less than $1 million in December 31, 2002, 2001 and 2000. It also
    includes our natural gas and oil activities, which were sold in 2002.

     The reconciliations of EBIT to income from continuing operations and
segment assets to total assets are presented below:

<Table>
<Caption>
                                                              YEAR ENDED DECEMBER 31,
                                                              ------------------------
                                                               2002     2001     2000
                                                              ------   ------   ------
                                                                   (IN MILLIONS)
<S>                                                           <C>      <C>      <C>
Total EBIT..................................................   $194     $ 93     $140
Interest and debt expense...................................    (23)     (23)     (24)
Affiliated interest income..................................      4       11       22
Income taxes................................................    (59)     (26)     (50)
                                                               ----     ----     ----
     Income from continuing operations......................   $116     $ 55     $ 88
                                                               ====     ====     ====
</Table>

<Table>
<Caption>
                                                                AS OF DECEMBER 31,
                                                             ------------------------
                                                              2002     2001     2000
                                                             ------   ------   ------
                                                                  (IN MILLIONS)
<S>                                                          <C>      <C>      <C>
Pipeline...................................................  $1,295   $1,004   $1,001
Field Services.............................................      93       78       53
Other......................................................      --       33       32
                                                             ------   ------   ------
     Total segment assets..................................   1,388    1,115    1,086
Discontinued operations....................................      22      145      103
                                                             ------   ------   ------
     Total consolidated assets.............................  $1,410   $1,260   $1,189
                                                             ======   ======   ======
</Table>

12. TRANSACTIONS WITH MAJOR CUSTOMERS

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

<Table>
<Caption>
                                                              2002     2001     2000
                                                              ----     ----     ----
                                                                  (IN MILLIONS)
<S>                                                           <C>      <C>      <C>
Public Service Company of Colorado(1).......................  $88      $94      $85
</Table>

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

(1) Our contracts with Public Service Company include 1,557 BBtu/d that expire
    between 2007 and 2025. Of this amount, 1,095 Bbtu/d expires in 2007.

                                        35
<PAGE>

13. SUPPLEMENTAL CASH FLOW INFORMATION

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

<Table>
<Caption>
                                                              2002    2001    2000
                                                              ----    ----    ----
                                                                 (IN MILLIONS)
<S>                                                           <C>     <C>     <C>
Interest paid...............................................  $23     $22     $25
Income tax payments.........................................   27      13      49
</Table>

14. INVESTMENTS IN AND TRANSACTIONS WITH RELATED PARTIES

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

<Table>
<Caption>
                                                   TYPE OF     OWNERSHIP
                                                  ENTITIES     INTEREST     2002     2001
                                                 -----------   ---------    -----    -----
                                                                            (IN MILLIONS)
<S>                                              <C>           <C>          <C>      <C>
Coastal Limited Ventures, Inc..................  Corporation       4%       $ --      $14
El Paso Oil and Gas Resources Company, L.P.....         L.P.       4%         --       15
                                                                            ----      ---
       Total...................................                             $ --      $29
                                                                            ====      ===
</Table>

     In 1999, we transferred a production payment and the properties burdened by
the production payment to Coastal Limited Ventures, Inc. and El Paso Oil and Gas
Resources Company Inc., two separate subsidiaries of El Paso CGP, 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 influence over their operating or management decisions.

     In the fourth quarter of 2002, Coastal Limited Ventures, Inc. was
liquidated and its assets were distributed to its shareholders. We recognized a
$1 million dividend at the date of liquidation.

     Also in the fourth quarter, we sold our stock in CIG Exploration, one of
our wholly owned subsidiaries, to CIGE Holdco, Inc., a wholly owned subsidiary
of El Paso CGP. CIG Exploration owned our investment in El Paso Oil and Gas
Resources Company, L.P. Prior to the sale we recognized a $13 million dividend
related to our investment in El Paso Oil and Gas Resources Company, L.P. See
Note 2 for a further discussion of this sale.

     Subject to the limitations discussed in Note 7, we participate in El Paso's
and its affiliates cash management program which matches short-term cash
surpluses and needs of its participating affiliates, thus minimizing total
borrowing from outside sources. Our continued participation in the program may
be dependent on the final rule following the FERC's Cash Management NOPR
discussed in Note 8. We had advanced $469 million at December 31, 2002, at a
market rate of interest which was 1.5%. At December 31, 2001, we had advanced
$232 million at a market rate of interest which was 2.1%. These receivables are
due upon demand; however, as of December 31, 2002, we have classified $444
million of this amount as non-current because we do not anticipate settlement
within the next twelve months.

     At December 31, 2002 and 2001, we had accounts receivable from related
parties of $36 million and $53 million. In addition, we had accounts payable to
related parties of $9 million and $51 million at December 31, 2002 and 2001.
These balances were incurred in the normal course of our business. As a result
of El Paso's credit rating downgrades, we maintained $2 million as of December
31, 2002, in contractual deposits related to our affiliates' transportation
contracts on our system.

     El Paso has allocated a portion of its general and administrative expenses
to us since 2001. The allocation is based on the estimated level of effort
devoted to our operations and the relative size of our EBIT, gross property and
payroll. For the years ended December 2002 and 2001 the annual charges were $22
million and $36 million. During 2002 and 2001, El Paso Natural Gas Company and
Tennessee Gas Pipeline Company allocated payroll and other expenses to us
associated with our shared pipeline services. The allocated expenses

                                        36
<PAGE>

are based on the estimated level of staff and their expenses to provide the
services. For the years ended December 2002 and 2001, the annual charges were
$16 million and $10 million. In 2000, we performed most of our own
administrative functions. During 2002, 2001, and 2000 we also provided some
administrative functions for our affiliates. We, in turn, allocated
administrative and general operating costs to our affiliates based on reasonable
contractual levels for the services provided. These services are reported as
reimbursement of operating expenses. We believe all the allocation methods are
reasonable.

     Beginning after the merger in 2001, we entered into transactions with other
El Paso subsidiaries in the normal course of our business to transport, sell and
purchase natural gas which increased our affiliated revenue and charges. Our
Field Services segment sells gas and liquids and provides gathering and
processing services to El Paso's Merchant Energy segment. In 2002 and 2001, the
revenues recognized were $105 million and $79 million. Our Pipeline segment
sells gas and provides transportation services to El Paso's Merchant Energy
segment. In 2002 and 2001, the revenues recognized were $25 million and $17
million. During 2002 and 2001, we incurred operation expenses related to natural
gas purchase and transportation costs of $25 million and $60 million. As
discussed more fully in Note 8, we also have a transportation service agreement
with Wyoming Interstate Company, Ltd. that extends through 2007. Services
provided by these affiliates 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>
                                                              2002   2001    2000
                                                              ----   -----   ----
                                                                 (IN MILLIONS)
<S>                                                           <C>    <C>     <C>
Revenues....................................................  $167   $ 191   $ 89
Operation and maintenance expenses..........................   (65)   (106)   (16)
Reimbursement of operating expenses.........................     5       4      7
</Table>

15. SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

     The table below presents our summarized quarterly financial information.
For the quarter ended March 31, 2002 and each of the quarters in 2001, our
summarized quarterly financial information includes reclassifications for
discontinued operations. See Note 2 for a further discussion.

<Table>
<Caption>
                                                         QUARTERS ENDED
                                         -----------------------------------------------
                                         DECEMBER 31   SEPTEMBER 30   JUNE 30   MARCH 31   TOTAL
                                         -----------   ------------   -------   --------   -----
                                                              (IN MILLIONS)
<S>                                      <C>           <C>            <C>       <C>        <C>
2002
  Operating revenues...................     $115           $81         $ 91       $96      $383
  Operating income.....................       48            33           32        41       154
  Income from continuing operations....       59            18           18        21       116
  Discontinued operations, net of
     income taxes......................        6            22            8         5        41
  Net income...........................       65            40           26        26       157
2001
  Operating revenues...................     $100           $89         $101       $86      $376
  Merger-related costs.................       --            --           19        12        31
  Operating income.....................       37            23            5        25        90
  Income from continuing operations....       26            12            2        15        55
  Discontinued operations, net of
     income taxes......................        6            10            8        14        38
  Net income...........................       32            22           10        29        93
</Table>

                                        37
<PAGE>

                       REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and Stockholder of
Colorado Interstate Gas Company:

     In our opinion, the consolidated financial statements in the Index
appearing under Item 15(a)(1) present fairly, in all material respects, the
consolidated financial position of Colorado Interstate Gas Company and
subsidiaries (the "Company") at December 31, 2002 and 2001, and the consolidated
results of their operations and their cash flows for each of the two years in
the period ended December 31, 2002 in conformity with accounting principles
generally accepted in the United States of America. In addition, in our opinion,
the financial statement schedule listed in the index under Item 15(a)(2)
presents fairly, in all material respects, the information set forth therein
when read in conjunction with the related consolidated financial statements.
These financial statements and the financial statement schedule are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements and the financial statement schedule based
on our audits. We conducted our audits of these statements in accordance with
auditing standards generally accepted in the United States of America, which
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

     As discussed in Note 6, the Company adopted Statement of Financial
Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and
Hedging Activities, on January 1, 2001.

     As discussed in Note 10, during 2001, the Company changed the measurement
date used to account for postretirement benefits other than pensions from
December 31 to September 30.

     We audited the adjustments described in Note 2 and Note 11 that were
applied to restate the disclosures of 2000 discontinued operations and segment
information in the accompanying financial statements to give retroactive effect
to the reporting of discontinued operations and 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 25, 2003

                                        38
<PAGE>

                          INDEPENDENT AUDITORS' REPORT

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

     We have audited the consolidated statements of income, stockholders' equity
and cash flows (none of which are presented herein) of Colorado Interstate Gas
Company (an indirect, wholly owned subsidiary of El Paso CGP Company, formerly
The Coastal Corporation) and subsidiaries (the "Company") for the year 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 audit.

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

     In our opinion, such consolidated financial statements present fairly, in
all material respects, Colorado Interstate Gas Company's results of operations
and cash flows for the year ended December 31, 2000, in conformity with
accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Denver, Colorado
February 23, 2001

                                        39
<PAGE>

                                  SCHEDULE II

                        COLORADO INTERSTATE GAS COMPANY

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

<Table>
<Caption>
                                      BALANCE AT    CHARGED TO    CHARGED TO                      BALANCE
                                      BEGINNING     COSTS AND       OTHER                         AT END
            DESCRIPTION               OF PERIOD      EXPENSES      ACCOUNTS     DEDUCTIONS(2)    OF PERIOD
            -----------               ----------    ----------    ----------    -------------    ---------
<S>                                   <C>           <C>           <C>           <C>              <C>
2002
  Legal Reserves....................     $19           $ (7)         $ --           $(10)           $ 2
  Environmental Reserves............       7              8            --             (2)            13
  Provision for Refunds.............       5              7            --             (8)             4
  Allowance for Doubtful Accounts...      --              1             2             --              3
2001
  Legal Reserves....................     $22           $ --          $ (3)          $ --            $19
  Environmental Reserves............       4             --             3             --              7
  Provision for Refunds.............      --              5            --             --              5
2000
  Legal Reserves....................     $42           $(17)(1)      $ (3)          $ --            $22
  Environmental Reserves............       1             --             3             --              4
</Table>

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

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

(2) These amounts represent cash payments.

                                        40
<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.

ITEM 14. CONTROLS AND PROCEDURES

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

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

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

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

                                        41
<PAGE>

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

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

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

                                        42
<PAGE>

                                    PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

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

     1. Financial statements 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...........................   17
Consolidated Balance Sheets.................................   18
Consolidated Statements of Cash Flows.......................   19
Consolidated Statements of Stockholder's Equity.............   20
Notes to Consolidated Financial Statements..................   21
Report of Independent Accountants...........................   38
</Table>

     2. Financial statement schedules.

<Table>
<S>                                                           <C>
          Schedule II -- Valuation and qualifying
           accounts.........................................   40
          All other schedules are omitted because they are
        not applicable, or the required information is
        disclosed in the financial statements or
        accompanying notes.

     3. Exhibit list........................................   44
</Table>

     (B) REPORTS ON FORM 8-K.

     None.

                                        43
<PAGE>

                        COLORADO INTERSTATE GAS COMPANY

                                  EXHIBIT LIST
                               DECEMBER 31, 2002

     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 (Exhibit 3.A to our 2001 Form 10-K).
          *3.B           By-laws dated June 24, 2002.
          10.A           Purchase and Sale Agreement by and between Colorado
                         Interstate Gas Company, El Paso Production GOM Inc. and CIG
                         Production Company, L.P., and Pioneer Natural Resources USA,
                         Inc. dated as of April 8, 2002 (Exhibit 10.A to our Form 8-K
                         filed April 23, 2002).
          10.B           Purchase and Sale Agreement by and between Colorado
                         Interstate Gas Company and Pioneer Natural Resources USA,
                         Inc. dated as of April 13, 2002 (Exhibit 10.B to our Form
                         8-K filed April 23, 2002).
         *99.A           Certification of Principal Executive Officer pursuant to 18
                         U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the
                         Sarbanes-Oxley Act of 2002. A signed original of this
                         written statement required by sec. 906 has been provided to
                         Colorado Interstate Gas Company and will be retained by
                         Colorado Interstate Gas Company and furnished to the
                         Securities and Exchange Commission or its staff upon
                         request.
         *99.B           Certification of Principal Financial Officer pursuant to 18
                         U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the
                         Sarbanes-Oxley Act of 2002. A signed original of this
                         written statement required by sec. 906 has been provided to
                         Colorado Interstate Gas Company and will be retained by
                         Colorado Interstate Gas Company and furnished to the
                         Securities and Exchange Commission or its staff upon
                         request.
</Table>

UNDERTAKING

     We hereby undertake, pursuant to Regulation S-K, Item 601(b), paragraph
(4)(iii), to furnish to the U.S. 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.

                                        44
<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 27th day of March 2003.

                                          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
                            ---------                                       -----                      ----
<C>    <C>                                                    <S>                                 <C>

                /s/ JOHN W. SOMERHALDER II                    Chairman of the Board, Chief        March 27, 2003
 --------------------------------------------------------       Executive Officer and Director
                 (John W. Somerhalder II)                       (Principal Executive Officer)

                 /s/ PATRICIA A. SHELTON                      President and Director              March 27, 2003
 --------------------------------------------------------
                  (Patricia A. Shelton)

                    /s/ GREG G. GRUBER                        Senior Vice President, Chief        March 27, 2003
 --------------------------------------------------------       Financial Officer and Treasurer
                     (Greg G. Gruber)                           (Principal Financial and
                                                                Accounting Officer)
</Table>

                                        45
<PAGE>

                                 CERTIFICATION

I, John W. Somerhalder II, certify that:

     1. I have reviewed this annual report on Form 10-K of Colorado Interstate
Gas Company;

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

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

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

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

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

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

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

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

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

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

                                              /s/ JOHN W. SOMERHALDER II
                                          --------------------------------------
                                                  John W. Somerhalder II
                                                  Chairman of the Board
                                              (Principal Executive Officer)
                                             Colorado Interstate Gas Company
Date: March 27, 2003

                                        46
<PAGE>

                                 CERTIFICATION

I, Greg G. Gruber, certify that:

     1. I have reviewed this annual report on Form 10-K of Colorado Interstate
Gas Company;

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

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

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

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

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

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

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

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

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

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

                                                  /s/ GREG G. GRUBER
                                          --------------------------------------
                                                      Greg G. Gruber
                                                  Senior Vice President,
                                          Chief Financial Officer and Treasurer
                                              (Principal Financial Officer)
                                             Colorado Interstate Gas Company
Date: March 27, 2003

                                        47
<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 (Exhibit 3.A to our 2001 Form 10-K).
          *3.B           By-laws dated June 24, 2002.
          10.A           Purchase and Sale Agreement by and between Colorado
                         Interstate Gas Company, El Paso Production GOM Inc. and CIG
                         Production Company, L.P., and Pioneer Natural Resources USA,
                         Inc. dated as of April 8, 2002 (Exhibit 10.A to our Form 8-K
                         filed April 23, 2002).
          10.B           Purchase and Sale Agreement by and between Colorado
                         Interstate Gas Company and Pioneer Natural Resources USA,
                         Inc. dated as of April 13, 2002 (Exhibit 10.B to our Form
                         8-K filed April 23, 2002).
         *99.A           Certification of Principal Executive Officer pursuant to 18
                         U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the
                         Sarbanes-Oxley Act of 2002. A signed original of this
                         written statement required by sec. 906 has been provided to
                         Colorado Interstate Gas Company and will be retained by
                         Colorado Interstate Gas Company and furnished to the
                         Securities and Exchange Commission or its staff upon
                         request.
         *99.B           Certification of Principal Financial Officer pursuant to 18
                         U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the
                         Sarbanes-Oxley Act of 2002. A signed original of this
                         written statement required by sec. 906 has been provided to
                         Colorado Interstate Gas Company and will be retained by
                         Colorado Interstate Gas Company and furnished to the
                         Securities and Exchange Commission or its staff upon
                         request.
</Table>

                                        48