<PAGE>   1

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                       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, 2000 OR

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

                FOR THE TRANSITION PERIOD FROM        TO

                         COMMISSION FILE NUMBER 1-4874

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

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

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

      Registrant's telephone number, including area code:  (713) 420-2131

          Securities registered pursuant to Section 12(b) of the Act:

<TABLE>
<CAPTION>
            TITLE OF EACH CLASS                  NAME OF EACH EXCHANGE ON WHICH REGISTERED
            -------------------                  -----------------------------------------
<S>                                             <C>
      10% Senior Debentures, due 2005                     New York Stock Exchange
     6.85% Senior Debentures, due 2037
</TABLE>

     Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months, and (2) has been subject to such filing
requirements for the past 90 days.  Yes [X]  No [ ]

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

     Common Stock, no par value. Shares outstanding on March 19, 2001: 10

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

                   DOCUMENTS INCORPORATED BY REFERENCE: None
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<PAGE>   2

                        COLORADO INTERSTATE GAS COMPANY

                               TABLE OF CONTENTS

<TABLE>
<CAPTION>
ITEM NO.                             CAPTION                              PAGE
--------                             -------                              ----
<S>        <C>                                                            <C>
                                    PART I
Item 1.    Business....................................................     1
Item 2.    Properties..................................................     5
Item 3.    Legal Proceedings...........................................     5
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.........................................     6
Item 6.    Selected Financial Data.....................................     *
Item 7.    Management's Discussion and Analysis of Financial Condition
           and Results of Operations...................................     6
Item 7A.   Quantitative and Qualitative Disclosures About Market
           Risk........................................................     8
Item 8.    Financial Statements and Supplementary Data.................     9
Item 9.    Changes in and Disagreements with Accountants on Accounting
           and Financial Disclosure....................................    28

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

                                   PART IV
Item 14.   Exhibits, Financial Statement Schedules, and Reports on Form
           8-K.........................................................    28

Signatures.............................................................    29
</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
Bbls     = barrels
Bcf      = billion cubic feet
MBbls    = thousand barrels
Mcf      = thousand cubic feet
Mcfe     = thousand cubic feet of gas equivalents
MMcf     = million cubic feet
</TABLE>

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

                                       (i)
<PAGE>   3

                                     PART I

ITEM 1. BUSINESS

                                  INTRODUCTION

     In January 2001, we became a wholly owned subsidiary of El Paso Corporation
through the merger of a wholly owned El Paso subsidiary with The Coastal
Corporation. In the merger, each share of Coastal common stock and Class A
common stock was converted on a tax-free basis into 1.23 shares of El Paso
common stock. The outstanding convertible preferred stock of Coastal was
exchanged tax free for El Paso common stock on the same basis as if the
preferred stock had been converted into Coastal common stock immediately prior
to the merger. El Paso issued a total of approximately 271 million shares of El
Paso common stock, including approximately 4 million shares issued in exchange
for outstanding Coastal stock options.

     We are a Delaware corporation organized in 1927. All of our outstanding
common stock is owned by Coastal Natural Gas Company, which is a wholly owned
subsidiary of El Paso CGP Company (formerly Coastal). We own and operate an
interstate natural gas pipeline system and also have gas and oil exploration and
production operations.

     Our selected financial information by industry segment is in Item 8,
Financial Statements and Supplementary Data, Note 7, which is incorporated
herein by reference.

                               NATURAL GAS SYSTEM

OPERATIONS

     We are involved in the production, purchase, gathering, processing,
transportation, storage and sale of natural gas. Our gas transmission system
extends from natural gas production areas in the Panhandle Field of Texas and is
directly or indirectly connected to every major supply basin in the Rocky
Mountain region. Our pipeline system serves two major markets, one along the
Front Range of the Rocky Mountains in Colorado and Wyoming and the second
interconnects with other pipelines transporting gas to California and the
Midwest.

     Our principal transmission facilities consist of approximately 4,400 miles
of pipeline and 56 compressor stations, with a design capacity of 2,290 MMcf/d.
During 2000, we transported natural gas volumes averaging approximately 60
percent of our capacity. Along our system, we also have approximately 29 Bcf of
working gas storage capacity and own four underground natural gas storage
fields; three located in Colorado and one in Kansas.

     Deliveries on our system for the years 2000, 1999 and 1998 were as follows:

<TABLE>
<CAPTION>
                                                           TOTAL SYSTEM     DAILY AVERAGE
                                                            DELIVERIES    SYSTEM DELIVERIES
YEAR                                                          (BCF)            (MMCF)
----                                                       ------------   -----------------
<S>                                                        <C>            <C>
2000.....................................................      485              1,325
1999.....................................................      454              1,245
1998.....................................................      480              1,315
</TABLE>

     In addition to our transmission and storage activities, we own or control
proved reserves that were estimated to total 202 Bcf, 228 Bcf, and 243 Bcf at
December 31, 2000, 1999, and 1998. These estimates are based on a report by
Huddleston & Co., Inc., our independent engineers. We also maintain, for our own
account, 2.5 Bcf of natural gas in underground storage fields and have an
additional 37.8 Bcf of base natural gas in our four storage fields. From our
total reserves, primarily located in the Panhandle Field, we are committed to
sell 77 percent to Pioneer Natural Resources USA, Inc. The remaining production
may be sold to third parties.

     We provide gathering and processing services on an unbundled or stand-alone
basis. Our processing terms are not regulated by the Federal Energy Regulatory
Commission (FERC), but we are required to provide

                                        1
<PAGE>   4

open access to our processing facilities. Our natural gas gathering and
processing facilities are located throughout the production areas adjacent to
our transmission system, with most of our gathering facilities connected
directly to our transmission system. Our gathering facilities, excluding
facilities in the Panhandle Field that are used to provide gathering services
regulated by FERC, consist of approximately 2,400 miles of gathering lines. We
own and operate four natural gas processing plants. These plants, with a total
operating capacity of approximately 477 MMcf/d, recover mainly propane, butanes,
natural gasoline, sulfur and other by-products, which are sold to refineries,
chemical plants and other customers. Our gas processing plants recovered
approximately 31 million gallons of liquid hydrocarbons in 2000, compared to 38
million gallons in 1999 and 46 million gallons in 1998. Additionally, we
processed approximately 36 million gallons of liquid hydrocarbons owned by
others in 2000, compared to 24 million gallons in 1999 and 25 million gallons in
1998.

REGULATORY ENVIRONMENT

     Our interstate systems are regulated by FERC under the Natural Gas Act of
1938 and the Natural Gas Policy Act of 1978. Our system operates under FERC
approved tariffs that establish rates, terms, and conditions under which our
system provides services to its customers. Generally, FERC's authority extends
to:

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

     - certification and construction of new facilities;

     - extension or abandonment of services and facilities;

     - maintenance of accounts and records;

     - regulatory accounting policies;

     - depreciation and amortization policies;

     - acquisition and disposition of facilities;

     - initiation and discontinuation of services; and

     - various other matters.

     Our pipeline system has a tariff established through filings with FERC and
has a variety of terms and conditions, each of which affects our operations and
our ability to recover fees for the services we provide. By and large, changes
to these fees or terms can only be implemented upon approval by FERC.

     We are also subject to the Natural Gas Pipeline Safety Act of 1968 that
establishes pipeline and liquefied natural gas plant safety requirements. We are
also subject to environmental legislation and regulations. Our systems have a
continuing program of inspection designed to keep all of our facilities in
compliance with pollution control and pipeline safety requirements. We believe
that our systems are in substantial compliance with the applicable requirements.

     We are also subject to regulation with respect to safety requirements in
the design, construction, operation and maintenance of our interstate natural
gas transmission and storage facilities by the U.S. Department of
Transportation. Additionally, we are subject to similar safety requirements from
the U.S. Department of Labor's Occupational Safety and Health Administration
related to our processing plants. Operations on United States government land
are regulated by the U.S. Department of the Interior.

     For further discussion of our rates and regulatory matters, see Item 8,
Financial Statements and Supplementary Data, Note 6.

MARKETS AND COMPETITION

     We serve two major markets, our "on-system" market, consisting of the
utilities 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 or California. We face different types of competition in
both markets. In the on-system market, competition comes from local supply in
the Denver-Julesburg basin, from an intrastate pipeline directly serving Denver,
and from off-system shippers who can deliver their gas in that market,

                                        2
<PAGE>   5

supplanting our transportation for utility customers. The primary criterion for
success in this market is the ability to serve a very volatile load reliably, at
a competitive price. In the off-system market, we face competition in our supply
area from two major pipelines serving the California and Pacific Northwest
markets. We also face competition from competitors whose supply is produced in
Texas, Oklahoma, and Kansas. These competitors can displace our deliveries into
the pipelines serving the Midwestern markets. The primary criterion for success
in this market is the strength of pricing differentials between Wyoming and
Oklahoma.

     Our full capacity is contracted under firm transportation agreements, with
the bulk of these agreements extending into 2007. The largest portion of these
agreements is with Public Service Company of Colorado and will expire in April
2007. We are actively negotiating with all shippers who have near-term expiring
contracts for contract renewal and are optimistic that our ability to serve the
Front Range market reliably and competitively, coupled with reasonably strong
pricing differentials affecting off-system markets, will result in successful
renewal of the expiring contracts.

                     GAS AND OIL EXPLORATION AND PRODUCTION

     We have domestic gas and oil production operations. The gas we produce is
delivered primarily to our interstate natural gas pipeline system while the
crude oil and condensate produced are sold at the wellhead to oil purchasing
companies at prevailing market prices. The production of gas and oil is subject
to regulation in the states in which we operate.

     In 1999, we conveyed several oil and gas properties to affiliated companies
in exchange for common stock, resulting in a reduction of our proved reserves of
approximately 76 Bcf of natural gas equivalents. Our investments in the
affiliated companies are being accounted for using the cost method.

     The following table presents our natural gas and oil, condensate and
natural gas liquids production volumes, including quantities attributable to our
natural gas system, for the years ended December 31:

<TABLE>
<CAPTION>
                                                              2000     1999     1998
                                                             ------   ------   ------
<S>                                                          <C>      <C>      <C>
Exploration and Production
  Natural Gas (MMcf).......................................   3,663    5,495   10,949
  Oil, Condensate and Natural Gas Liquids (MBbls)..........     160       80       64
Natural Gas System
  Natural Gas (MMcf).......................................  33,433   35,634   39,058
  Oil, Condensate and Natural Gas Liquids (MBbls)..........      25       24       44
</TABLE>

     The following table summarizes realized sales price and unit cost
information of our exploration and production operations for the years ended
December 31:

<TABLE>
<CAPTION>
                                                              2000     1999     1998
                                                             ------   ------   ------
<S>                                                          <C>      <C>      <C>
Average realized sales price:
  Natural Gas -- $/Mcf.....................................  $ 3.80   $ 1.93   $ 1.69
  Oil, Condensate and Natural Gas Liquids -- $/Bbl.........   16.12    15.30    13.36
Average production cost per unit -- $/Mcfe.................  $ 0.38   $ 0.59   $ 0.58
</TABLE>

     The following table details our gross and net acreage held under natural
gas and oil mineral leases at December 31, 2000.

<TABLE>
<CAPTION>
                                   UNDEVELOPED        DEVELOPED             TOTAL
                                  -------------   -----------------   -----------------
AREA                              GROSS    NET     GROSS      NET      GROSS      NET
----                              -----   -----   -------   -------   -------   -------
<S>                               <C>     <C>     <C>       <C>       <C>       <C>
Exploration and Production......  9,863   9,461     8,247     4,109    18,110    13,570
Natural Gas System..............     --      --   262,474   259,276   262,474   259,276
                                  -----   -----   -------   -------   -------   -------
                                  9,863   9,461   270,721   263,385   280,584   272,846
                                  =====   =====   =======   =======   =======   =======
</TABLE>

                                        3
<PAGE>   6

     The net developed acreage is concentrated principally in Texas (93 percent)
and Oklahoma (7 percent). The net undeveloped acreage is principally in Utah (99
percent).

     The following table details our participation in wells drilled during the
years 1998 through 2000.

     Exploration and Production

<TABLE>
<CAPTION>
                                                    2000          1999          1998
                                                 -----------   -----------   -----------
                                                 GROSS   NET   GROSS   NET   GROSS   NET
                                                 -----   ---   -----   ---   -----   ---
<S>                                              <C>     <C>   <C>     <C>   <C>     <C>
Development Wells
  Natural Gas..................................   --     --     11      7     20     18
  Dry Holes....................................   --     --     --     --     --     --
                                                  --      --    --     --     --     --
                                                  --     --     11      7     20     18
                                                  --      --    --     --     --     --
</TABLE>

     Natural Gas System

<TABLE>
<S>                                              <C>     <C>   <C>     <C>   <C>     <C>
Development Wells
  Natural Gas..................................    7      1     22     13      6      6
  Dry Holes....................................   --     --     --     --     --     --
                                                  --     --     --     --     --     --
                                                   7      1     22     13      6      6
                                                  --     --     --     --     --     --
          Total................................    7      1     33     20     26     24
                                                  ==     ==     ==     ==     ==     ==
</TABLE>

     The following table details our domestic productive wells at December 31,
2000.

<TABLE>
<CAPTION>
TYPE OF WELL                                                  GROSS   NET
------------                                                  -----   ---
<S>                                                           <C>     <C>
Exploration and Production
  Natural Gas...............................................    21      6
                                                               ---    ---
          Total Exploration and Production..................    21      6
                                                               ---    ---
Natural Gas System
  Oil.......................................................     9      8
  Natural Gas...............................................   809    789
                                                               ---    ---
          Total Natural Gas System..........................   818    797
                                                               ---    ---
               Total........................................   839    803
                                                               ===    ===
</TABLE>

     For information on our reserves of oil and gas, see Item 8, Financial
Statements and Supplementary Data, Note 10, which is incorporated herein by
reference.

     We compete with major integrated oil companies and independent oil and gas
companies for suitable prospects for oil and gas drilling operations. The
availability of a ready market for gas discovered and produced depends on
numerous factors frequently beyond our control. These factors include the extent
of gas discovery and production by other producers, crude oil imports, the
marketing of competitive fuels, and the proximity, availability and capacity of
gas pipelines and other facilities for the transportation and marketing of gas.
The production and sale of oil and gas is subject to a variety of federal and
state regulations, including regulation of production levels.

                                        4
<PAGE>   7

                                 ENVIRONMENTAL

     A description of our environmental activities is included in Item 8,
Financial Statements and Supplementary Data, Note 6, and is incorporated herein
by reference.

                                   EMPLOYEES

     At January 31, 2001, we had 662 employees, none of which are subject to
collective bargaining agreements.

ITEM 2. PROPERTIES

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

     We are of the opinion that we have satisfactory title to the properties
owned and used in our businesses, subject to liens for current taxes, liens
incident to minor encumbrances, and easements and restrictions that do not
materially detract from the value of such property or the interests therein or
the use of such properties in our businesses. We believe that our physical
properties are adequate and suitable for the conduct of our business in the
future.

ITEM 3. LEGAL PROCEEDINGS

     See Item 8, Financial Statements and Supplementary Data, Note 6, which 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 share, is owned by Coastal Natural Gas, and
accordingly, there is no public trading market for our securities. Coastal
Natural Gas is an indirect subsidiary of Coastal.
On January 29, 2001, Coastal 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 $39 million and $41 million to our parent in 2000 and
1998.

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.

                                        5
<PAGE>   8

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

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

     In January 2001, we became a wholly owned subsidiary of El Paso through the
merger of a wholly owned El Paso subsidiary with Coastal. In the merger, El Paso
issued a total of approximately 271 million shares of its common stock,
including approximately 4 million shares issued in exchange for outstanding
Coastal stock options.

     On January 30, 2001, we completed an employee restructuring, that resulted
in the reduction of approximately 180 full time positions through a combination
of early retirements and terminations. These actions will result in severance
and termination charges, retention payments to employees retained on a
transition basis following the merger, and the acceleration of employee benefit
payments under existing benefit plans and employment contracts. We expect a
majority of these charges to occur in the first quarter of 2001.

     The final cost of the merger-related activities and the charges we will
incur as we continue to integrate our activities with El Paso are not fully
known at this time. However, we expect that most of these charges will be
recorded in 2001.

                             RESULTS OF OPERATIONS

     The following table presents earnings before interest and income taxes, or
EBIT, by segment and in total for the years ended December 31, 2000 and 1999:

<TABLE>
<CAPTION>
                                                              2000    1999
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
EARNINGS BEFORE INTEREST EXPENSE AND INCOME TAXES
Natural gas.................................................  $192    $159
                                                              ----    ----
Exploration and production..................................    11       3
                                                              ----    ----
     Consolidated EBIT......................................  $203    $162
                                                              ====    ====
</TABLE>

NATURAL GAS

     Natural gas operating results and an analysis of these results for the
years ended December 31, 2000 and 1999 are as follows:

<TABLE>
<CAPTION>
                                                              2000    1999
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
Operating revenues..........................................  $375    $299
Operating expenses..........................................   202     153
Other income, net...........................................    19      13
EBIT........................................................   192     159
Total throughput volume (MMcf/d)............................  1,325   1,245
</TABLE>

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

     Operating revenues from natural gas operations increased $76 million in
2000 as compared to 1999 due to an increase in average gas sales prices, net of
reservations; a decrease in reservations related to contingent obligations;
increased transportation volumes and increased extracted products revenue due to
higher product prices in 2000.

     Operating expenses increased $49 million in 2000 as compared to 1999 due
primarily to an increase in transportation and net gas system balancing
requirements, increased gas royalties expense, increased

                                        6
<PAGE>   9

employee-related expenses, an increase in outside services and operating
supplies expense and increased depreciation, depletion and amortization
primarily due to increased depreciable property.

     Other income, net increased by $6 million in 2000 over the comparable 1999
period primarily due to higher interest rates on larger loan balances with
affiliated companies.

EXPLORATION AND PRODUCTION

     Exploration and production operating results and an analysis of these
results for the years ended December 31, 2000 and 1999 are as follows:

<TABLE>
<CAPTION>
                                                               2000     1999
                                                              ------   ------
                                                               (IN MILLIONS)
<S>                                                           <C>      <C>
Operating revenues..........................................  $   16   $   12
Operating expenses..........................................       8       11
Other income, net...........................................       3        2
EBIT........................................................      11        3
Natural gas production (MMcf)...............................   3,663    5,495
Oil, condensate and natural gas liquids production
  (MBbls)...................................................     160       80
Average realized sales price (dollars):
  Gas (per Mcf).............................................  $ 3.80   $ 1.93
  Oil, condensate and natural gas liquids (per barrel)......   16.12    15.30
</TABLE>

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

     Operating revenues from exploration and production increased $4 million in
2000 as compared to 1999 due to higher gas sales prices and an increase in
crude, condensate, and natural gas liquids volumes, partially offset by a
decrease in natural gas sales volumes.

     Operating expenses decreased by $3 million in 2000 as compared to 1999
primarily due to decreased production volumes, lower management service fees and
a decrease in depreciation, depletion and amortization, partially offset by
increased production taxes.

     Other income, net increased by $1 million in 2000 compared to 1999 due to
higher interest income.

INCOME TAXES

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

     Income taxes increased by $15 million in 2000 as compared to 1999 primarily
as a result of an increase in income before taxes. The effective federal income
tax rate was 35 percent in both years.

      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 to be made in
good faith, assumed facts or bases almost always vary from the actual results,
and the differences between assumed facts or bases and actual results can be
material, depending upon the circumstances. Where, in any forward-looking
statement, we or our management express an expectation or belief as to future
results, that expectation or belief is expressed in good faith and is believed
to have a reasonable basis. We cannot assure you, however, that the statement of
expectation or belief will result or be achieved or accomplished. The words
"believe," "expect," "estimate," "anticipate" and similar expressions will
generally identify forward-looking statements.

                                        7
<PAGE>   10

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     The following table presents hypothetical changes in fair values in our
debt obligations at December 31, 2000 and 1999. The modeling technique used
measures the change in fair values arising from selected changes in interest
rates. Market changes reflect immediate hypothetical changes in interest rates
at December 31. Fair values are calculated as the net present value of the
expected cash flows of the financial instrument.

<TABLE>
<CAPTION>
                                                             10% INCREASE         10% DECREASE
                                                          ------------------   ------------------
                                                FAIR      FAIR     INCREASE    FAIR     INCREASE
                                                VALUE     VALUE   (DECREASE)   VALUE   (DECREASE)
                                              ---------   -----   ----------   -----   ----------
                                                                 (IN MILLIONS)
<S>                                           <C>         <C>     <C>          <C>     <C>
Impact of changes in market rates of
  interest on
Long-term debt subject to fixed interest
  rates
  2000......................................    $299      $293       $(6)      $306        $7
  1999......................................     289       280        (9)       298         9
</TABLE>

     We have notes receivable from related parties with carrying values of $331
million and $297 million at December 31, 2000 and 1999 and a note payable to a
related party with a carrying value of $2 million at December 31, 1999. These
notes earn interest at a variable rate tied to market rates of interest, and
therefore, the carrying amount is a reasonable estimate of fair value. A 10
percent change in interest rates from the December 31 levels would not have a
material impact on our income.

                                        8
<PAGE>   11

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES

                       CONSOLIDATED STATEMENTS OF INCOME
                                 (IN MILLIONS)

<TABLE>
<CAPTION>
                                                              YEAR ENDED DECEMBER 31,
                                                              ------------------------
                                                               2000     1999     1998
                                                              ------   ------   ------
<S>                                                           <C>      <C>      <C>
Operating revenues
  Nonaffiliates.............................................   $290     $225     $293
  Affiliates................................................    101       86       87
                                                               ----     ----     ----
                                                                391      311      380
                                                               ----     ----     ----
Operating expenses
  Cost of gas sold..........................................     --       --       68
  Operation and maintenance.................................    175      135      152
  Depreciation, depletion and amortization..................     35       29       33
                                                               ----     ----     ----
                                                                210      164      253
                                                               ----     ----     ----
Operating income............................................    181      147      127
                                                               ----     ----     ----
Other income, net...........................................     22       15       16
                                                               ----     ----     ----
Income before interest and income taxes.....................    203      162      143

Other expenses
  Interest expense..........................................     24       25       24
  Income taxes..............................................     65       50       41
                                                               ----     ----     ----
                                                                 89       75       65
                                                               ----     ----     ----
Net income..................................................   $114     $ 87     $ 78
                                                               ====     ====     ====
</TABLE>

                            See accompanying notes.

                                        9
<PAGE>   12

                COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES

                          CONSOLIDATED BALANCE SHEETS
                      (IN MILLIONS, EXCEPT SHARE AMOUNTS)

<TABLE>
<CAPTION>
                                                               DECEMBER 31,
                                                              ---------------
                                                               2000     1999
                                                              ------   ------
<S>                                                           <C>      <C>
                                   ASSETS

Current assets
  Cash......................................................  $    1   $    1
  Notes receivable from affiliates..........................     331      297
  Accounts receivable.......................................      62       49
  Accounts receivable from affiliates.......................      18       40
  Materials and supplies, at average cost...................       7        8
  Current portion of deferred income taxes..................      29       40
                                                              ------   ------
          Total current assets..............................     448      435
                                                              ------   ------
Plant, property and equipment, at cost
  Gas pipeline..............................................   1,299    1,249
  Gas and oil properties, at full-cost......................     100       97
                                                              ------   ------
                                                               1,399    1,346
  Accumulated depreciation, depletion, and amortization.....     732      705
                                                              ------   ------
          Total plant, property, and equipment, net.........     667      641
                                                              ------   ------
Other assets
  Investments in related parties............................      62       64
  Other deferred charges....................................      23       46
                                                              ------   ------
          Total other assets................................      85      110
                                                              ------   ------
          Total assets......................................  $1,200   $1,186
                                                              ======   ======

                    LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities
  Note payable to affiliate.................................  $   --   $    2
  Accounts payable and accrued expenses.....................      95      119
  Accounts payable to affiliates............................       9       20
  Income taxes payable......................................      15       22
                                                              ------   ------
          Total current liabilities.........................     119      163
                                                              ------   ------
Debt
  Long-term debt............................................     280      280
                                                              ------   ------
Deferred credits
  Deferred income taxes.....................................     130      118
  Other.....................................................      12       41
                                                              ------   ------
          Total deferred credits............................     142      159
                                                              ------   ------
Stockholder's equity
  Common stock authorized 10,000 shares; issued and
     outstanding 10 shares at stated value..................      28       28
  Additional paid-in capital................................      19       19
  Retained earnings.........................................     612      537
                                                              ------   ------
          Total stockholder's equity........................     659      584
                                                              ------   ------
          Total liabilities and stockholder's equity........  $1,200   $1,186
                                                              ======   ======
</TABLE>

                            See accompanying notes.

                                        10
<PAGE>   13

                COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES

                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                                 (IN MILLIONS)

<TABLE>
<CAPTION>
                                                              YEAR ENDED DECEMBER 31,
                                                              -----------------------
                                                               2000    1999     1998
                                                              ------   -----   ------
<S>                                                           <C>      <C>     <C>
Cash flow from operating activities
  Net income................................................  $ 114    $ 87    $  78
  Add items not requiring cash:
     Depreciation, depletion and amortization...............     35      29       33
     Deferred income taxes..................................     23       7        3
  Working capital and other changes
     Accounts receivable....................................    (13)     (7)      22
     Accounts receivable from affiliates....................     22       3       (4)
     Accounts payable and accrued expenses..................    (24)     (4)     (16)
     Accounts payable to affiliates.........................    (11)    (21)      15
     Income taxes payable...................................     (7)     --       16
     Other..................................................     (3)     --       (1)
                                                              -----    ----    -----
          Net cash provided by operating activities.........    136      94      146
                                                              -----    ----    -----
Cash flow from investing activities
  Purchases of plant, property and equipment................    (63)    (46)     (84)
  Proceeds from sale of plant, property and equipment.......     --      11       --
  Investments in related parties............................      2      (4)      (5)
  Net increase in notes receivable from affiliates..........    (34)    (54)     (23)
                                                              -----    ----    -----
          Net cash used in investing activities.............    (95)    (93)    (112)
                                                              -----    ----    -----
Cash flow from financing activities
  Net increase (decrease) in note payable to affiliate......     (2)     --        3
  Common dividends paid.....................................    (39)     --      (41)
                                                              -----    ----    -----
          Net cash used in financing activities.............    (41)     --      (38)
                                                              -----    ----    -----
Net increase (decrease) in cash.............................     --       1       (4)
Cash at beginning of period.................................      1      --        4
                                                              -----    ----    -----
Cash at end of period.......................................  $   1    $  1    $  --
                                                              =====    ====    =====
</TABLE>

                            See accompanying notes.

                                        11
<PAGE>   14

                COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES

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

<TABLE>
<CAPTION>
                                                              YEAR ENDED DECEMBER 31,
                                                              ------------------------
                                                               2000     1999     1998
                                                              ------   ------   ------
<S>                                                           <C>      <C>      <C>
Common stock, par value $5 per share, authorized 10,000
  shares; issued and outstanding 10 shares at stated
  value.....................................................   $ 28     $ 28     $ 28
Additional paid-in capital..................................     19       19       19
Retained earnings
  Beginning balance.........................................    537      450      413
     Net income.............................................    114       87       78
     Dividends on common stock..............................    (39)      --      (41)
                                                               ----     ----     ----
  Ending balance............................................    612      537      450
                                                               ----     ----     ----
          Total.............................................   $659     $584     $497
                                                               ====     ====     ====
</TABLE>

                            See accompanying notes.

                                        12
<PAGE>   15

                COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

  Basis of Presentation

     We are a subsidiary of Coastal Natural Gas Company, a wholly owned
subsidiary of El Paso CGP Company (formerly The Coastal Corporation). In
connection with Coastal's merger with a wholly owned subsidiary of El Paso in
January 2001, Coastal became a subsidiary of El Paso. Coastal then changed its
name to El Paso CGP Company. We were originally acquired by Coastal in 1972. Our
financial statements are presented on a historical cost basis and do not reflect
the cost basis to Coastal Natural Gas when they acquired us. The preparation of
these financial statements in conformity with generally accepted accounting
principles requires us to make estimates and assumptions that affect the
reported amounts of assets, liabilities, revenues and expenses. Our actual
results are likely to differ from those estimates and assumptions used.

  Principles of Consolidation

     Our consolidated financial statements include accounts of all wholly owned
subsidiaries, after eliminating all significant intercompany transactions. The
equity method of accounting is used for investments in which we are able to
exert significant influence, but not control over operating and financial
policies. Other investments where we are unable to exert significant influence
are accounted for by the cost method.

  Cash and Cash Equivalents

     Cash equivalents include time deposits, certificates of deposit and all
highly liquid instruments with original maturities of three months or less. We
made cash payments for interest, net of amounts capitalized, of $25 million in
each of the years 2000, 1999 and 1998. Cash payments for income taxes amounted
to $49 million, $44 million and $21 million in 2000, 1999 and 1998.

  Nature of Operations and Concentrations of Credit Risk

     We are involved in the production, purchase, gathering, processing,
transportation, storage and sale of natural gas primarily in the Texas Panhandle
and Rocky Mountain regions of the United States. We operate under arrangements
with other companies, including distributors, intrastate and interstate
pipelines, producers, brokers, marketers and end-users. As a result, we have a
concentration of receivables due from these customers. This may affect our
overall credit risk in that the customers may be similarly affected by changes
in economic, regulatory and other factors. Trade receivables are generally not
collateralized; however, we analyze customers' credit positions prior to
extending credit.

  Natural Gas Imbalances

     Natural gas imbalances result from differences in gas volumes received from
and delivered to our transportation and storage customers and arise when a
customer delivers more or less gas into our pipeline than they take out. We
value these gas imbalances due to or from shippers and operators at an
appropriate index price. Natural gas imbalances are settled in cash or made up
in-kind, subject to the pipelines' various terms.

  Price Risk Management Activities

     We periodically enter into swaps, futures and other contracts to hedge the
price risk of natural gas anticipated to be sold. We defer the impact of changes
in the market value of these contracts until such time as the hedged transaction
is completed. At that time, the impact of the changes in fair market value of
these contracts is recognized in income.

                                        13
<PAGE>   16

  Plant, Property and Equipment

     Property additions and betterments are capitalized at cost. Property
additions include capitalized interest costs allocable to construction. These
costs amounted to $.5 million, $.3 million and $.5 million in 2000, 1999 and
1998. All costs incurred in the acquisition, exploration and development of gas
and oil properties, including unproductive wells, are capitalized under the full
cost method of accounting. These costs include the costs of all unproved
properties and internal costs directly related to acquisition and exploration
activities. All other general and administrative costs, as well as production
costs, are expensed as incurred.

     We provide for depreciation of gas system facilities on a straight-line
basis with rates that vary by type of property (2 percent to 27 percent during
1998 through 2000). Depreciation, depletion and amortization of gas and oil
properties are provided on the unit-of-production basis whereby the unit rate
for depreciation, depletion and amortization is determined by dividing the total
unrecovered carrying value of gas and oil properties (excluding costs related to
unevaluated properties) plus estimated future development costs by the estimated
proved reserves included therein. Estimated proved reserves were prepared by
Huddleston & Co., Inc., our independent engineers for the Natural Gas System,
while the Exploration and Production portions were prepared by El Paso CGP's
engineers and reviewed by Huddleston. The average exploration and production
segment amortization rate per equivalent unit of a thousand cubic feet of gas
production for oil and gas operations was $1.015 for 2000, $.87 for 1999 and
$.89 for 1998. Unamortized costs of proved properties are subject to a ceiling
which limits such costs to the estimated future net cash flows from proved gas
and oil properties, net of related income tax effects, discounted at 10 percent.
If the unamortized costs are greater than this ceiling, any excess will be
charged to depreciation, depletion and amortization expense. No such charge was
required in the periods presented.

     The cost of minor property units replaced or retired, net of salvage, is
credited to plant accounts and charged to accumulated depreciation, depletion
and amortization. Since provisions for depreciation, depletion and amortization
expense are generally made on a composite basis, no adjustments to accumulated
depreciation, depletion and amortization are made in connection with retirements
or other dispositions occurring in the ordinary course of business. Gain or loss
on sales of major property units is credited or charged to income.

  Accounting for Derivative Instruments and Hedging Activities

     In June of 1998, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for
Derivative Instruments and Hedging Activities. In June of 1999, the FASB
extended the adoption date of SFAS No. 133 through the issuance of SFAS No. 137,
Deferral of the Effective Date of SFAS 133. In June 2000, the FASB issued SFAS
No. 138, Accounting for Certain Derivative Instruments and Certain Hedging
Activities, which also amended SFAS No. 133. SFAS No. 133, and its amendments
and interpretations, establishes accounting and reporting standards for
derivative instruments, including derivative instruments embedded in other
contracts, and derivative instruments used for hedging activities. It requires
that we measure all derivative instruments at their fair value, and classify
them as either assets or liabilities on our balance sheet, with a corresponding
offset to income or other comprehensive income depending on their designation,
their intended use, or their ability to qualify as hedges under the standard.

     We adopted SFAS No. 133 on January 1, 2001, and applied the standard to all
derivative instruments that existed on that date, except for derivative
instruments embedded in other contracts. As provided for in SFAS No. 133, we
applied the provisions of the standard to derivative instruments embedded in
other contracts issued, acquired, or substantially modified after December 31,
1998.

                                        14
<PAGE>   17

     Based on commodity prices existing at December 31, 2000, we will reflect
the impact of our adoption of SFAS No. 133 as of January 1, 2001, by recording a
cumulative effect transition adjustment as a charge to other comprehensive
income of $2 million, net of income taxes and an increase in liabilities of $2
million. This represents the fair value of our derivative instruments designated
as cash flow hedges.

  Income Taxes

     We are a member of a consolidated group which files a consolidated federal
income tax return. Members of the consolidated group with taxable income are
charged with the amount of income taxes as if they filed separate federal income
tax returns, and members providing deductions and credits which result in income
tax savings are allocated credits for such savings. We follow the liability
method of accounting for deferred income taxes as required by the provisions of
SFAS No. 109, Accounting for Income Taxes.

  Revenue Recognition

     We recognize revenues for the sale of our products in the period of
delivery. Revenue for services are recognized in the period the services are
provided.

  Reclassification of Prior Period Statements

     Minor reclassifications of prior period statements have been made to
conform with current reporting practices. The effect of the reclassifications
was not material to our financial position, operating results or cash flows.

2. LONG-TERM DEBT

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

<TABLE>
<CAPTION>
                                                              2000    1999
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
10% Senior Debentures, due 2005.............................  $180    $180
6.85% Senior Debentures, due 2037...........................   100     100
                                                              ----    ----
                                                              $280    $280
                                                              ====    ====
</TABLE>

     Each holder of our 6.85 percent senior debentures has the right to require
us to redeem such debentures, in whole or in part, on June 15, 2007, at a
redemption price equal to 100 percent of the aggregate principal amount thereof
plus accrued and unpaid interest.

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

<TABLE>
<CAPTION>
                                                                 (IN
                                                              MILLIONS)
<S>                                                           <C>
2001........................................................    $ --
2002........................................................      --
2003........................................................      --
2004........................................................      --
2005........................................................     180
Thereafter..................................................     100
                                                                ----
          Total long-term debt, including current
           maturities.......................................    $280
                                                                ====
</TABLE>

                                        15
<PAGE>   18

3. FAIR VALUE OF FINANCIAL INSTRUMENTS

     We have estimated the fair value amounts of our financial instruments using
appropriate market information and valuation methodologies. Considerable
judgment is required to develop the estimates of fair value and the estimates
provided are not necessarily indicative of the amounts that could be realized in
a current market exchange. The carrying amounts and estimated fair values of our
financial instruments at December 31 are as follows:

<TABLE>
<CAPTION>
                                                             2000               1999
                                                       ----------------   ----------------
                                                       CARRYING   FAIR    CARRYING   FAIR
                                                        AMOUNT    VALUE    AMOUNT    VALUE
                                                       --------   -----   --------   -----
                                                                  (IN MILLIONS)
<S>                                                    <C>        <C>     <C>        <C>
Financial assets
  Cash...............................................    $  1     $  1      $  1     $  1
  Notes receivable from affiliates...................     331      331       297      297
Financial liabilities
  Long-term debt.....................................     280      299       280      289
  Note payable to affiliate..........................      --       --         2        2
</TABLE>

     The carrying values of cash, notes receivable from affiliates and note
payable to affiliate are reasonable estimates of their fair values. The
estimated values of our long-term debt are based on interest rates at December
31, 2000 and 1999 for new issues with similar remaining maturities.

4. INCOME TAXES

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

<TABLE>
<CAPTION>
                                                              2000   1999   1998
                                                              ----   ----   ----
                                                                (IN MILLIONS)
<S>                                                           <C>    <C>    <C>
Current
  Federal...................................................  $40    $40    $35
  State.....................................................    2      3      3
                                                              ---    ---    ---
                                                               42     43     38
                                                              ---    ---    ---
Deferred
  Federal...................................................   21      6      2
  State.....................................................    2      1      1
                                                              ---    ---    ---
                                                               23      7      3
                                                              ---    ---    ---
  Total tax expense.........................................  $65    $50    $41
                                                              ===    ===    ===
</TABLE>

     El Paso CGP and the Internal Revenue Service Appeals Office have concluded
a tentative settlement of the adjustments proposed to El Paso CGP's federal
income tax returns filed for the years 1988 through 1994. Examination of El Paso
CGP's federal income tax returns filed for the years 1995, 1996 and 1997 began
in 1999 and is ongoing. We believe that adequate provisions for federal income
taxes have been reflected in our consolidated financial statements.

                                        16
<PAGE>   19

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

<TABLE>
<CAPTION>
                                                              2000   1999   1998
                                                              ----   ----   ----
                                                                (IN MILLIONS)
<S>                                                           <C>    <C>    <C>
Tax expense at the statutory federal rate of 35%............  $63    $48    $42
Increase (decrease)
  State income tax cost.....................................    3      3      2
  Tight sands gas credit....................................   --     (2)    (3)
  Other.....................................................   (1)     1     --
                                                              ---    ---    ---
Income tax expense..........................................  $65    $50    $41
                                                              ===    ===    ===
Effective tax rate..........................................   35%    35%    32%
                                                              ===    ===    ===
</TABLE>

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

<TABLE>
<CAPTION>
                                                              2000    1999
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
Deferred tax liabilities
  Excess of book basis over tax basis of plant, property and
     equipment..............................................  $129    $116
  Other.....................................................     1       2
                                                              ----    ----
          Total deferred tax liabilities....................   130     118
                                                              ----    ----
Deferred tax assets
  Provisions for rate refunds and contested claims..........    15      25
  Accrued expenses..........................................    12      11
  Other.....................................................     2       4
                                                              ----    ----
          Total deferred tax assets.........................    29      40
                                                              ====    ====
          Net deferred tax liability........................  $101    $ 78
                                                              ----    ----
</TABLE>

5. BENEFIT PLANS

     We participate in the non-contributory pension plan of El Paso CGP which
covers substantially all of our employees. The pension plan provides benefits
based on final average monthly compensation and years of service, subject to
maximum limitations as defined in the plan. As of December 31, 2000, the pension
plan did not have an unfunded accumulated benefit obligation. We made no
contributions to the pension plan for 2000, 1999 or 1998. Assets of the pension
plan are not segregated or restricted by participating employers, and pension
obligations for our employees would remain the obligation of the pension plan if
we were to withdraw.

     We also make contributions to a thrift plan, which is a trusteed, voluntary
and contributory plan for our eligible employees. We match 100 percent of
participant basic contributions up to 8 percent, with the matching contribution
being made in the common stock of Coastal. Our contributions, which are based on
matching employee contributions, amounted to approximately $2 million for 2000,
$3 million for 1999 and $2 million for 1998.

     We provide health care and life insurance benefits for all of our
employees. The estimated costs of retiree benefit payments are accrued during
the years the employee provides services.

     In conjunction with the El Paso merger, some of our benefit plans will be
merged into comparable El Paso benefit plans, while other benefit plans will be
terminated.

                                        17
<PAGE>   20

     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 postretirement benefits.

<TABLE>
<CAPTION>
                                                              2000    1999
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
Change in postretirement benefit obligation
  Benefit obligation at beginning of period.................  $14.6   $14.3
  Service cost..............................................     .3      .3
  Interest cost.............................................    1.1      .9
  Participant contributions.................................     .5      .5
  Actuarial loss............................................     .3      .1
  Benefits paid.............................................   (1.6)   (1.5)
                                                              -----   -----
  Postretirement benefit obligation at end of period........  $15.2   $14.6
                                                              =====   =====
Change in plan assets
  Fair value of plan assets at beginning of period..........  $ 9.5   $ 9.1
  Actual return on plan assets..............................     .4      .5
  Employer contributions....................................    1.4     1.4
  Administrative expenses...................................    (.1)    (.7)
  Benefits paid.............................................   (1.1)    (.8)
                                                              -----   -----
  Fair value of plan assets at end of period................  $10.1   $ 9.5
                                                              =====   =====
Reconciliation of funded status
  Funded status at end of period............................  $(5.1)  $(5.1)
  Unrecognized actuarial gain...............................   (4.3)   (4.7)
  Unrecognized transition obligation........................   10.0    10.8
                                                              -----   -----
  Prepaid postretirement benefit asset at December 31.......  $ 0.6   $ 1.0
                                                              =====   =====
</TABLE>

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

<TABLE>
<CAPTION>
                                                                  YEAR ENDED
                                                                 DECEMBER 31,
                                                              ------------------
                                                              2000   1999   1998
                                                              ----   ----   ----
                                                                (IN MILLIONS)
<S>                                                           <C>    <C>    <C>
Postretirement benefit obligations include the following
  components
  Service cost..............................................  $ .3   $ .3   $ .3
  Interest cost.............................................   1.1     .9     .9
  Expected return on assets.................................   (.3)   (.2)   (.2)
  Amortization of transition obligation.....................    .8     .8     .8
  Amortization of net actuarial gain........................   (.2)   (.3)   (.4)
                                                              ----   ----   ----
  Net postretirement benefit cost...........................  $1.7   $1.5   $1.4
                                                              ====   ====   ====
</TABLE>

                                        18
<PAGE>   21

     The assumed health care cost trend rate used in measuring the accumulated
postretirement benefit obligation was 7.8 percent in 2000, declining gradually
to 6.0 percent by the year 2004. The assumed health care cost trend rate used in
measuring the accumulated postretirement benefit obligation was 8.4 percent in
1999 and 9.0 percent in 1998. A one percentage point increase in the assumed
health care cost trend rate for each year would increase the accumulated
postretirement benefit obligation as of December 31, 2000 by approximately 4.11
percent and the net postretirement health care cost by approximately 3.53
percent. A one percentage point decrease in the assumed health care cost trend
rate for each year would decrease the accumulated postretirement benefit
obligation as of December 31, 2000 by approximately 4.47 percent and the net
postretirement health care cost by approximately 4.05 percent. The assumed
discount rate used in determining the accumulated postretirement benefit
obligation was 7.75 percent in 2000 and 8.0 percent in 1999, and the expected
long-term rate of return on assets was 4.3 percent in 2000 and 1999.

6. COMMITMENTS AND CONTINGENCIES

  Legal Proceedings

     In 1997, we and a number of our affiliates were named defendants in actions
brought by Jack Grynberg on behalf of the U.S. Government under the False Claims
Act. Generally, these complaints allege an industry-wide conspiracy to under
report the heating value as well as the volumes of the natural gas produced from
federal and Native American lands, which deprived the U.S. Government of
royalties. These matters have been consolidated for pretrial purposes. (In re:
Natural Gas Royalties Qui Tam Litigation, U.S. District Court for the District
of Wyoming.)

     We and a number of our affiliates were named defendants in an action styled
Quinque Operating Company, et al v. Gas Pipelines and Their Predecessors, et al,
filed in 1999, in the District Court of Stevens County, Kansas. This class
action complaint alleges that the defendants mismeasured natural gas volumes and
heating content of natural gas on non-federal and non-Native American lands. The
Quinque complaint, once transferred to the same court handling the Grynberg
complaint, has been sent back to the Kansas State Court for further proceedings.

     We are also a named defendant in other lawsuits arising in the ordinary
course of our business.

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

  Environmental

     Our operations are subject to extensive and evolving federal, state and
local environmental laws and regulations. Compliance with these laws and
regulations can be costly. Additionally, governmental authorities may enforce
the laws and regulations with a variety of civil and criminal enforcement
measures, including monetary penalties and remediation requirements.

                                        19
<PAGE>   22

     We spent approximately $.4 million in 2000 on environmental capital
projects and anticipate capital expenditures of approximately $1 million per
year over the next several years in order to comply with these laws and
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 that compliance
with all applicable laws and regulations will not have a material adverse impact
on our financial position, operating results or cash flows.

  Rates and Regulatory Matters

     In the 1997 settlement of our general rate proceeding with FERC, we agreed
to file a new general rate case, with a proposed effective date no later than
October 1, 2001, under Section 4 of the Natural Gas Act. We plan to file a new
general rate case by the end of the first quarter 2001. The new rates are
expected to reflect a rate increase for all or most services. In addition,
several regulatory issues remain unresolved among us, our customers, our
suppliers and FERC. We have made provisions which represent our assessment of
the ultimate resolution of these issues. While we cannot predict with certainty
the final outcome or the timing of the resolution of all of our regulatory
matters, we believe the ultimate resolution of these issues will not have a
material adverse effect on our financial position, operating results or cash
flows.

  Commitments

     We had rental expense of approximately $5 million, in each of the years
2000, 1999 and 1998, excluding leases covering natural resources. The aggregate
minimum lease payments under existing noncapitalized long-term leases are
estimated to be $4 million, $3 million, $3 million, $3 million and $1 million
for the years 2001-2005 and an immaterial amount thereafter.

     We executed a service agreement with Wyoming Interstate Company, Ltd., an
affiliate, providing for the availability of pipeline transportation capacity
through December 31, 2007. Under the service agreement, we are required to make
minimum payments on a monthly basis with minimum annual payments of $9 million
per year for 2001-2003 and $3 million for later years. We expensed approximately
$9 million and $5 million in 2000 and 1999 related to this agreement.

7. SEGMENT INFORMATION

     Natural gas system operations and natural gas and oil exploration and
production are the two segments of our operations. Separate management of each
segment is required because each line is subject to different production,
marketing and technology strategies.

     Natural gas system operations involve the production, purchase, gathering,
processing, transportation, storage and sale of natural gas, principally to and
for public utilities, industrial customers, other pipelines, and other gas
customers, as well as the operation of natural gas liquids extraction plants.

     Gas and oil exploration and production operations involve primarily the
development and production of natural gas, crude oil, condensate and natural gas
liquids. Sales are made to affiliated companies, industrial users, interstate
pipelines and distribution companies in the Rocky Mountain, Central and
Southwest United States.

     The accounting policies of the individual segments are the same as those
described in Note 1.

                                        20
<PAGE>   23

     Information related to our segments for the years ended December 31, 2000,
1999 and 1998 are as follows:

<TABLE>
<CAPTION>
                                                              2000   1999   1998
                                                              ----   ----   ----
                                                                (IN MILLIONS)
<S>                                                           <C>    <C>    <C>
Operating Revenues
  Natural gas system........................................  $375   $299   $368
  Exploration and production................................    16     12     19
  Exploration and production intersegment revenue
     eliminations...........................................    --     --     (7)
                                                              ----   ----   ----
     Consolidated totals....................................  $391   $311   $380
                                                              ====   ====   ====
Income Before Interest and Income Taxes
  Natural gas system........................................  $192   $159   $141
  Exploration and production................................    11      3      2
                                                              ----   ----   ----
     Consolidated totals....................................  $203   $162   $143
                                                              ====   ====   ====
Depreciation, Depletion and Amortization
  Natural gas system........................................  $ 31   $ 24   $ 23
  Exploration and production................................     4      5     10
                                                              ----   ----   ----
     Consolidated totals....................................  $ 35   $ 29   $ 33
                                                              ====   ====   ====
Equity Income From Investments
  Natural gas system........................................  $ --   $ --   $  7
  Exploration and production................................    --     --     --
                                                              ----   ----   ----
     Consolidated totals....................................  $ --   $ --   $  7
                                                              ====   ====   ====
Capital Expenditures
  Natural gas system........................................  $ 61   $ 40   $ 69
  Exploration and production................................     2      6     15
                                                              ----   ----   ----
     Consolidated totals....................................  $ 63   $ 46   $ 84
                                                              ====   ====   ====
</TABLE>

     Our assets by segment as of December 31, 2000, 1999 and 1998 are as
follows:

<TABLE>
<CAPTION>
                                                              2000     1999     1998
                                                             ------   ------   ------
                                                              (IN MILLIONS)
<S>                                                          <C>      <C>      <C>
Assets
  Natural gas..............................................  $1,167   $1,142   $1,085
  Exploration and production...............................      33       44       31
                                                             ------   ------   ------
     Consolidated totals...................................  $1,200   $1,186   $1,116
                                                             ======   ======   ======
</TABLE>

     Revenues from sales, storage and transportation of natural gas to
individual customers amounting to 10 percent or more of our consolidated
revenues were as indicated below:

<TABLE>
<CAPTION>
                                                                  YEAR ENDED
                                                                 DECEMBER 31,
                                                              ------------------
                                                              2000   1999   1998
                                                              ----   ----   ----
                                                                (IN MILLIONS)
<S>                                                           <C>    <C>    <C>
Public Service Company of Colorado
  Amount....................................................  $85    $87    $112
                                                              ===    ===    ====
  Percent...................................................   21%    27%     28%
                                                              ===    ===    ====
Pioneer Natural Resources USA, Inc.
  Amount....................................................  $49    $36    $ 40
                                                              ===    ===    ====
  Percent...................................................   12%    11%     10%
                                                              ===    ===    ====
</TABLE>

                                        21
<PAGE>   24

     Revenues from any other single customer did not amount to 10 percent or
more of our consolidated revenues for the years ended December 31, 2000, 1999
and 1998.

     Deliveries from our production in the Texas Panhandle Field are made to
markets in the Panhandle region. Transportation services are provided for
brokers, producers, marketers, distributors, end-users and other pipelines. We
extend credit for sales, storage and transportation services provided to
qualifying companies.

8. TRANSACTIONS WITH RELATED PARTIES

     The Consolidated Statements of Income include the following major
transactions with related parties:

<TABLE>
<CAPTION>
                                              2000                1999                1998
                                        -----------------   -----------------   -----------------
                                                 PERCENT             PERCENT             PERCENT
                                        AMOUNT   OF TOTAL   AMOUNT   OF TOTAL   AMOUNT   OF TOTAL
                                        ------   --------   ------   --------   ------   --------
                                                              (IN MILLIONS)
<S>                                     <C>      <C>        <C>      <C>        <C>      <C>
Operating revenues
  Gathering and transportation........   $ 17         7%     $ 20         9%     $ 26        13%
  Gas sales...........................   $ 43        49%     $ 24        42%     $ 32        25%
  Extracted products and gas
     processing.......................   $ 18        73%     $ 12        78%     $ 12        82%
  Incidental gasoline, oil and
     condensate sales ................   $  2        39%     $  2        48%     $  2        59%
  Natural gas production..............   $  9        56%     $ 10        82%     $  6        47%
Operating expenses
  Gas purchases.......................   $ --        --%     $ --        --%     $  7        10%
  Gathering, transportation and
     compression......................   $  8        79%     $  5        69%     $  9        92%
</TABLE>

     Revenues from our gathering and transportation, gas sales and natural gas
production presented in the above table result from transactions with affiliates
handling merchant energy activities. Our extracted products and gas processing
revenues arise from transactions with our field operations affiliates. Our
incidental gasoline, oil and condensate sales are transactions with affiliates
involved in refining, marketing and trading activities. Our gas purchase
transactions are with an exploration and production affiliate, and our
gathering, transportation and compression costs and expenses arise from
transactions with an affiliate pipeline. Transactions with affiliates are based
on the same terms as nonaffiliate transactions.

     Services provided by us at cost to affiliated companies were $7 million for
2000, $10 million for 1999 and $8 million for 1998. Services provided by
affiliated companies to us at cost were $8 million for each of the years 2000,
1999 and 1998. The services we provided to affiliates, and by affiliates to us,
primarily reflect the allocation of costs relating to the sharing/operating of
facilities and general and administrative functions. Costs are allocated based
on several factors including revenue, property and payroll.

     We participate in a program which matches short-term cash excesses and
requirements of participating affiliates, thus minimizing total borrowings from
outside sources. We had advanced $331 million and $280 million to associated
companies at a market rate of interest at December 31, 2000 and 1999. Such
amount is repayable on demand. Additionally, at December 31, 1999, we had
advanced $17 million to an affiliate on a long-term basis at a market rate of
interest.

                                        22
<PAGE>   25

     Our investment in an affiliate, Coastal Medical Services, Inc., was $33
million and $35 million on December 31, 2000 and 1999. The affiliate has assumed
the responsibility for facilitating the management of a portion of our medical
obligations and the medical obligations of several other El Paso CGP
subsidiaries.

     In 1999, we conveyed several oil and gas properties to affiliated companies
in exchange for common stock, resulting in a reduction of our proved reserves of
approximately 76 Bcf of natural gas equivalents. Our investments in the
affiliated companies are being accounted for using the cost method.

9. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)

     Financial information by quarter is summarized below. In the opinion of
management, all adjustments necessary for a fair presentation have been made.

<TABLE>
<CAPTION>
                                                              2000 QUARTER ENDED
                                                  -------------------------------------------
                                                  MARCH 31,   JUNE 30,   SEPT. 30,   DEC. 31,
                                                  ---------   --------   ---------   --------
                                                                 (IN MILLIONS)
<S>                                               <C>         <C>        <C>         <C>
Revenues........................................     $93        $84         $79        $135
Other costs and expenses........................      62         64          63          88
                                                     ---        ---         ---        ----
  Net Income....................................     $31        $20         $16        $ 47
                                                     ===        ===         ===        ====
</TABLE>

<TABLE>
<CAPTION>
                                                              1999 QUARTER ENDED
                                                  -------------------------------------------
                                                  MARCH 31,   JUNE 30,   SEPT. 30,   DEC. 31,
                                                  ---------   --------   ---------   --------
                                                                 (IN MILLIONS)
<S>                                               <C>         <C>        <C>         <C>
Revenues........................................     $87        $70         $70        $84
Other costs and expenses........................      56         56          58         54
                                                     ---        ---         ---        ---
  Net Income....................................     $31        $14         $12        $30
                                                     ===        ===         ===        ===
</TABLE>

10. SUPPLEMENTAL INFORMATION ON NATURAL GAS AND OIL OPERATIONS (UNAUDITED)

     Reserves, capitalized costs, costs incurred in oil and gas acquisition,
exploration and development activities, results of operations and the
standardized measure of discounted future net cash flows are presented for the
exploration and production segment. Natural gas system reserves and the related
standardized measure of discounted future net cash flows are presented
separately for natural gas operations. All reserves are located in the United
States. The reserve information for the Natural Gas System shown below was
prepared by Huddleston, while the Exploration and Production portions are as
prepared by El Paso CGP engineers and reviewed by Huddleston. In 1999, we
conveyed several oil and gas properties to affiliated companies in exchange for
common stock, resulting in a reduction of our proved reserves of approximately
76 Bcf of natural gas equivalents. Our investments in affiliated companies are
being accounted for using the cost method.

Estimated Quantities of Proved Reserves

<TABLE>
<CAPTION>
                                                          NATURAL GAS         EXPLORATION
                                                            SYSTEM          AND PRODUCTION
                                                          -----------   -----------------------
COMPANY-OWNED RESERVES                                     DEVELOPED    DEVELOPED   UNDEVELOPED    TOTAL
----------------------                                    -----------   ---------   -----------   -------
<S>                                                       <C>           <C>         <C>           <C>
Natural Gas (MMcf)
  2000...................................................   175,353       6,141        2,270      183,764
  1999...................................................   197,649       6,877        1,144      205,670
  1998...................................................   211,761      91,302       21,739      324,802
Oil, Condensate and Natural Gas Liquids (MBbls)
  2000...................................................       231          81           28          340
  1999...................................................       249         140           19          408
  1998...................................................       237         383          167          787
</TABLE>

                                        23
<PAGE>   26

     Changes in proved reserves since the end of 1997 are shown in the following
table:

<TABLE>
<CAPTION>
                                                                        OIL, CONDENSATE AND
                                                    NATURAL GAS         NATURAL GAS LIQUIDS
                                               ---------------------   ---------------------
                                               NATURAL   EXPLORATION   NATURAL   EXPLORATION
                                                 GAS         AND         GAS         AND
TOTAL PROVED RESERVES                          SYSTEM    PRODUCTION    SYSTEM    PRODUCTION
---------------------                          -------   -----------   -------   -----------
                                                      (MMCF)                  (MBBLS)
<S>                                            <C>       <C>           <C>       <C>
Total, end of 1997...........................  248,248     114,083       349         906
Production during 1998.......................  (39,058)    (10,949)      (44)        (64)
Extensions and discoveries...................      404         338        --          --
Acquisitions.................................       --          --        --          --
Sales of reserves in-place...................       --     (13,619)       --        (192)
Revisions of previous quantity estimates and
  other......................................    2,167      23,188       (68)       (100)
                                               -------    --------       ---        ----
Total, end of 1998...........................  211,761     113,041       237         550
                                               -------    --------       ---        ----
Production during 1999.......................  (35,634)     (5,495)      (24)        (80)
Extensions and discoveries...................       --         930        --          19
Acquisitions.................................       --          --        --          --
Sales of reserves in-place...................       --          --        --          --
Revisions of previous quantity estimates and
  other......................................   21,522    (100,455)       36        (330)
                                               -------    --------       ---        ----
Total, end of 1999...........................  197,649       8,021       249         159
                                               -------    --------       ---        ----
Production during 2000.......................  (33,433)     (3,663)      (25)       (160)
Extensions and discoveries...................       --          --        --          --
Acquisitions.................................       --          --        --          --
Sales of reserves in-place...................       --        (525)       --          --
Revisions of previous quantity estimates and
  other......................................   11,137       4,578         7         110
                                               -------    --------       ---        ----
Total, end of 2000...........................  175,353       8,411       231         109
                                               =======    ========       ===        ====
</TABLE>

     Total proved reserves for the natural gas system exclude storage gas and
liquids volumes. The natural gas system storage gas volumes are 38,602 MMcf,
41,472 MMcf, and 41,213 MMcf and storage liquids volumes are approximately 237
MBbls, 301 MBbls, and 232 MBbls at December 31, 2000, 1999 and 1998. Volumes are
based on Huddleston's report and include estimates which differ slightly from
actuals.

Capitalized Costs Relating to Exploration and Production Activities

<TABLE>
<CAPTION>
                                                              DECEMBER 31,
                                                              -------------
                                                              2000    1999
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
Proved and Unproved Properties
  Proved Properties.........................................  $ 99    $ 96
  Unproved Properties.......................................     1       1
                                                              ----    ----
                                                               100      97
Accumulated depreciation, depletion and amortization........   (96)    (94)
                                                              ----    ----
                                                              $  4    $  3
                                                              ====    ====
</TABLE>

                                        24
<PAGE>   27

Costs Excluded from Amortization

     The following table summarizes the costs related to unevaluated properties
that are excluded from amounts subject to amortization at December 31, 2000. We
regularly evaluate these costs to determine whether impairment has occurred.

<TABLE>
<CAPTION>
                                                             YEARS COSTS INCURRED
                                                             ---------------------   PRIOR TO
                                                     TOTAL   2000    1999    1998      1998
                                                     -----   -----   -----   -----   --------
                                                             (IN MILLIONS)
<S>                                                  <C>     <C>     <C>     <C>     <C>
Property Acquisition...............................  $1.0     $--     $--    $1.0        --
Capitalized Interest...............................    .1      .1      --      --        --
                                                     ----     ---     ---    ----      ----
                                                     $1.1     $.1     $--    $1.0        --
                                                     ====     ===     ===    ====      ====
</TABLE>

Costs Incurred in Oil and Gas Acquisition, Exploration and Development
Activities

<TABLE>
<CAPTION>
                                                                  YEAR ENDED
                                                                 DECEMBER 31,
                                                              -------------------
                                                              2000   1999   1998
                                                              ----   ----   -----
                                                                 (IN MILLIONS)
<S>                                                           <C>    <C>    <C>
Property acquisition costs
  Proved....................................................  $ .1   $ .1   $ 1.8
  Unproved..................................................    --     --     1.4
Exploration costs...........................................    --     .1      .2
Development costs...........................................   2.3    5.9    11.4
</TABLE>

Results of Operations for Exploration and Production Activities

<TABLE>
<CAPTION>
                                                                  YEAR ENDED
                                                                 DECEMBER 31,
                                                              ------------------
                                                              2000   1999   1998
                                                              ----   ----   ----
                                                                (IN MILLIONS)
<S>                                                           <C>    <C>    <C>
Revenues
  Sales.....................................................  $15    $ 3    $  4
  Transfers.................................................    1      9      15
                                                              ---    ---    ----
     Total..................................................   16     12      19
Production costs............................................   (2)    (4)     (7)
Operating expenses..........................................   (1)    (1)     (2)
Depreciation, depletion and amortization....................   (4)    (5)    (10)
                                                              ---    ---    ----
                                                                9      2      --
Income tax (expense) benefit................................   (3)     1       3
                                                              ---    ---    ----
Results of operations for producing activities (excluding
  corporate overhead and interest costs)....................  $ 6    $ 3    $  3
                                                              ===    ===    ====
</TABLE>

     The average exploration and production segment amortization rate per Mcfe
was $1.015 in 2000, $0.87 in 1999 and $0.89 in 1998.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil
and Gas Reserve Quantities

     Future cash inflows for the years ended December 31, 2000, 1999 and 1998
from the sale of proved reserves and estimated production and development costs
as calculated by our engineers and reviewed by Huddleston are discounted at 10
percent after they are reduced by our estimate for future income taxes. The
calculations are based on year-end prices and costs, statutory tax rates and
nonconventional fuel source tax credits that relate to existing proved oil and
gas reserves in which we have mineral interests.

                                        25
<PAGE>   28

     The standardized measure is not intended to represent the market value of
reserves, and in view of the uncertainties involved in the reserve estimation
process, including the instability of energy markets as evidenced by changes in
both natural gas and crude oil prices, may be subject to material future
revisions.

<TABLE>
<CAPTION>
                                                             YEAR ENDED DECEMBER 31,
                                      ---------------------------------------------------------------------
                                              2000                    1999                    1998
                                      ---------------------   ---------------------   ---------------------
                                      NATURAL   EXPLORATION   NATURAL   EXPLORATION   NATURAL   EXPLORATION
                                        GAS         AND         GAS         AND         GAS         AND
                                      SYSTEM    PRODUCTION    SYSTEM    PRODUCTION    SYSTEM    PRODUCTION
                                      -------   -----------   -------   -----------   -------   -----------
                                                                  (IN MILLIONS)
<S>                                   <C>       <C>           <C>       <C>           <C>       <C>
Future cash inflows.................   $ 474       $ 53        $229         $20        $256        $ 228
Future production and development
  costs.............................    (110)        (7)        (74)         (7)        (79)        (119)
Future income tax (expenses)
  benefits..........................    (116)       (10)        (49)          3         (57)         (23)
                                       -----       ----        ----         ---        ----        -----
Future net cash flows...............     248         36         106          16         120           86
10% annual discount for estimated
  timing of cash flows..............     (89)       (10)        (41)         (2)        (51)         (37)
                                       -----       ----        ----         ---        ----        -----
Standardized measure of discounted
  future net cash flows.............   $ 159       $ 26        $ 65         $14        $ 69        $  49
                                       =====       ====        ====         ===        ====        =====
</TABLE>

     Principal sources of change in the standardized measure of discounted
future net cash flows during each year are:

<TABLE>
<CAPTION>
                                                             YEAR ENDED DECEMBER 31,
                                      ---------------------------------------------------------------------
                                              2000                    1999                    1998
                                      ---------------------   ---------------------   ---------------------
                                      NATURAL   EXPLORATION   NATURAL   EXPLORATION   NATURAL   EXPLORATION
                                        GAS         AND         GAS         AND         GAS         AND
                                      SYSTEM    PRODUCTION    SYSTEM    PRODUCTION    SYSTEM    PRODUCTION
                                      -------   -----------   -------   -----------   -------   -----------
                                                                  (IN MILLIONS)
<S>                                   <C>       <C>           <C>       <C>           <C>       <C>
Sales and transfers, net of
  production costs..................   $(52)       $(15)       $(36)       $ (8)       $(34)       $(13)
Net changes in prices and production
  costs.............................    150          10          (6)         13           3          (2)
Extensions and discoveries..........     --          --          --           1          --          --
Acquisitions........................     --          --          --          --          --          --
Sales of reserves in-place..........     --          --          --          --          --         (10)
Development costs incurred during
  the period that reduced estimated
  future development costs..........     --          --          --           2          --           8
Revisions of previous quantity
  estimates, timing and other.......     34          25          28         (56)          6          (8)
Accretion of discount...............      4          --           7           5           8           6
Net change in income taxes..........    (42)         (8)          3           8           6           7
                                       ----        ----        ----        ----        ----        ----
    Net change......................   $ 94        $ 12        $ (4)       $(35)       $(11)       $(12)
                                       ====        ====        ====        ====        ====        ====
</TABLE>

     None of the amounts include any value for natural gas system storage gas of
approximately 39 Bcf and liquids volumes of approximately 237 MBbls, at the end
of 2000. Volumes are based on Huddleston's report and include estimates which
differ slightly from actuals.

                                        26
<PAGE>   29

                          INDEPENDENT AUDITORS' REPORT

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

     We have audited the accompanying consolidated balance sheets of Colorado
Interstate Gas Company (an indirect, wholly owned subsidiary of El Paso CGP
Company (formerly The Coastal Corporation)) and subsidiaries as of December 31,
2000 and 1999, and the related consolidated statements of income, retained
earnings and additional paid-in capital and cash flows for each of the three
years in the period ended December 31, 2000. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.

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

     In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of Colorado Interstate Gas Company
and subsidiaries as of December 31, 2000 and 1999, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2000 in conformity with accounting principles generally accepted in
the United States of America.

DELOITTE & TOUCHE LLP

Denver, Colorado
February 23, 2001

                                        27
<PAGE>   30

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

     None.

                                    PART III

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

                                    PART IV

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

     (a) The following documents are filed as part of this report:

          1. Financial Statements and Supplemental Information.

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

<TABLE>
<CAPTION>
                                                              PAGE
                                                              ----
<S>                                                           <C>
Consolidated Statements of Income...........................    9
Consolidated Balance Sheets.................................   10
Consolidated Statements of Cash Flows.......................   11
Consolidated Statements of Stockholder's Equity.............   12
Notes to Consolidated Financial Statements..................   13
Independent Auditors' Report................................   27
</TABLE>

          2. Financial Statement Schedules.

            Schedules are omitted because they are not applicable.

          3. Exhibits.

<TABLE>
<CAPTION>
        EXHIBIT
         NUMBER                                  DESCRIPTION
        -------                                  -----------
<C>                      <S>
           3.A           Certificate of Incorporation of CIG, as amended.
           3.B           By-Laws of CIG dated October 11, 1979.
</TABLE>

     (b) Reports on Form 8-K.

     We filed a Current Report on Form 8-K dated February 2, 2001 announcing
that we became an indirect subsidiary of El Paso Corporation as the result of
the merger of a wholly owned subsidiary of El Paso with The Coastal Corporation.

                                        28
<PAGE>   31

                                   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 29th day of March 2001.

                                            COLORADO INTERSTATE GAS COMPANY

                                            By:  /s/ PATRICIA A. SHELTON
                                             -----------------------------------
                                                     Patricia A. Shelton
                                                          President
                                                (Principal Executive Officer)

     Pursuant to the requirements of the Securities Exchange Act of 1934, as
amended, this report has been signed below by the following persons on behalf of
Colorado Interstate Gas Company and in the capacities and on the dates
indicated:

<TABLE>
<CAPTION>
                      SIGNATURE                                     TITLE                    DATE
                      ---------                                     -----                    ----
<C>                                                    <S>                              <C>

               /s/ PATRICIA A. SHELTON                 President (Principal Executive   March 29, 2001
-----------------------------------------------------    Officer)
                (Patricia A. Shelton)

             /s/ JOHN W. SOMERHALDER II                Chairman of the Board and        March 29, 2001
-----------------------------------------------------    Director
              (John W. Somerhalder II)

                 /s/ GREG G. GRUBER                    Senior Vice President and Chief  March 29, 2001
-----------------------------------------------------    Financial Officer
                  (Greg G. Gruber)

                /s/ JEFFREY I. BEASON                  Senior Vice President and        March 29, 2001
-----------------------------------------------------    Controller
                 (Jeffrey I. Beason)                     (Chief Accounting Officer)

                 /s/ H. BRENT AUSTIN                   Executive Vice President and     March 29, 2001
-----------------------------------------------------    Director
                  (H. Brent Austin)

                 /s/ WILLIAM A. WISE                   Director                         March 29, 2001
-----------------------------------------------------
                  (William A. Wise)
</TABLE>

                                        29
<PAGE>   32

                                 EXHIBIT INDEX

<TABLE>
<CAPTION>
        EXHIBIT
         NUMBER                                  DESCRIPTION
        -------                                  -----------
<C>                      <S>

           3.A           Certificate of Incorporation of CIG, as amended. (Exhibit to
                         CIG's 1980 Form 10-K)
          *3.B           By-Laws of CIG dated October 11, 1979.
</TABLE>