<PAGE>   1
                                    FORM 10-K
                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

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

For the fiscal year ended DECEMBER 31, 1997

Commission File number 1-10216:

                          CHIEFTAIN INTERNATIONAL, INC.
             (Exact name of registrant as specified in its charter)

      ALBERTA, CANADA                                       NONE
(State or other jurisdiction                (I.R.S. Employer Identification No.)
of incorporation or organization)

1201 TORONTO DOMINION TOWER, EDMONTON CENTRE,
         EDMONTON, ALBERTA, CANADA                                   T5J 2Z1
(Address of Registrant's principal executive offices)              (Postal code)

Registrant's telephone number, including area code:               (403) 425-1950

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

Title of each class                    Name of each exchange on which registered
-------------------                    -----------------------------------------

Common Shares, no par value, of
     Chieftain International, Inc.                       American Stock Exchange

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:                 NONE

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

The aggregate market value of the voting stock of Chieftain International, Inc.
held by non-affiliates of said registrant on March 13, 1998 was
U.S.$306,126,520.

The number of shares outstanding of the common stock of Chieftain International,
Inc. on March 13,1998 was 13,576,675.

                       DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Chieftain International, Inc. Information Circular dated March
20, 1998 for its annual meeting of shareholders to be held on May 14, 1998, are
incorporated by reference into Part III hereof, to the extent indicated herein.
The Exhibits Index can be found on page 41 of this document.



<PAGE>   2

                          CHIEFTAIN INTERNATIONAL, INC.
                          1997 FORM 10-K ANNUAL REPORT

                                Table of Contents
<TABLE>
<CAPTION>
                                                                                                      Page
                                                PART I
<S>                                                                                                   <C>
   Item 1.  Business .................................................................................  3
              Segment Information ....................................................................  3
              Principal Properties ...................................................................  3
              Acreage ................................................................................  8
              Gas and Oil Capital Expenditures .......................................................  9
              Drilling Activity ......................................................................  9
              Wells .................................................................................. 10
              Reserves ............................................................................... 10
              Production Volumes, Prices and Costs ................................................... 10
              Marketing .............................................................................. 11
              Competition ............................................................................ 11
              Environmental Regulation ............................................................... 11
              Regulation and Political Risk .......................................................... 11
              Concentration of Gas Production ........................................................ 12
              Development of Additional Reserves ..................................................... 12
              Exploration and Production Risks ....................................................... 12
              Price Uncertainty ...................................................................... 12
              Employees .............................................................................. 12
              Glossary ............................................................................... 13
   Item 2.  Properties ............................................................................... 15
   Item 3.  Legal Proceedings ........................................................................ 15
   Item 4.  Submission of Matters to a Vote of Security Holders ...................................... 15
              Executive Officers of the Registrant ................................................... 15

                                                PART II

   Item 5.  Market for the Registrant's Securities and Related Stockholder Matters ................... 16
   Item 6.  Selected Consolidated Financial Data ..................................................... 16
   Item 7.  Management's Discussion and Analysis of Financial Condition and Results of Operations .... 18
   Item 8.  Financial Statements and Supplementary Data .............................................. 20
   Item 9.  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ..... 40

                                                PART III

   Item 10. Directors and Executive Officers ......................................................... 40
   Item 11. Executive Compensation ................................................................... 40
   Item 12. Security Ownership of Certain Beneficial Owners and Management ........................... 40
   Item 13. Certain Relationships and Related Transactions ........................................... 40

                                                PART IV

   Item 14. Exhibits and Reports on Form 8-K ......................................................... 40

Signatures ........................................................................................... 42
</TABLE>


                                        2

<PAGE>   3

                                     PART I

ITEM 1.   BUSINESS

Chieftain International, Inc. was incorporated under the Business Corporations
Act (Alberta) on November 23, 1988 and amalgamated on February 22, 1989 with a
wholly-owned subsidiary. *

The Company commenced operations on April 20, 1989 with the successful initial
public offering of 9,487,500 Common Shares which generated net proceeds of
$121.7 million. Upon the closing of the offering, the Company purchased assets
consisting primarily of natural gas and oil properties in the United States.

Chieftain is engaged directly and indirectly through subsidiary companies in gas
and oil exploration and production, primarily in the United States and also in
the U.K. sector of the North Sea. In addition, Chieftain is participating in an
exploration venture in the Sirte Basin of Libya.

The Company employs an experienced geological and geophysical staff which
generates exploration prospects utilizing advanced technology to process and
interpret 3-D seismic and other data.

In the United States, Chieftain's principal producing properties are located in
the federal waters of the Gulf of Mexico and in southeast Utah. Chieftain's
exploration acreage is located primarily in the federal waters of the Gulf of
Mexico. Minor interests are held onshore in Texas and in other areas of the
United States.

In the Gulf of Mexico, Chieftain holds interests in 149 offshore blocks of which
93 are exploratory and 56 are productive.

SEGMENT INFORMATION

Reference is made to page 39 hereof for financial information with respect to
the geographic segments of Chieftain for the years ended December 31, 1997, 1996
and 1995.

PRINCIPAL PROPERTIES

Chieftain's principal gas producing properties are located in U.S. federal
waters in the Gulf of Mexico and in the U.K. sector of the North Sea. Its
principal oil producing properties are located in the Paradox Basin of southeast
Utah, also referred to as the Four Corners area.

UNITED STATES GULF OF MEXICO AREA -- OFFSHORE

Chieftain concentrates its exploration and development activities in, and
devotes substantial managerial and financial resources to, the offshore Gulf of
Mexico area which accounted for most of Chieftain's gas production in 1997.
Activity in this area during 1997 was devoted to both exploration for and
development of reserves. Sixteen exploratory wells were drilled, of which eight
were successful, and ten development wells were drilled, of which nine were
successful.


-----------------------------
* Unless the context otherwise requires, reference to "Chieftain" or the
"Company" or the"Corporation" are to Chieftain International, Inc. and its
subsidiaries. For definitions of certain terms used throughout this report, see
"Glossary".

The Company's accounts are maintained, and all dollar amounts herein are stated,
in United States dollars unless otherwise indicated.


                                        3

<PAGE>   4

Substantial additions were made to Chieftain's acreage position in the Gulf of
Mexico during 1997. Interests in 13 federal blocks were acquired at competitive
lease sales and interests in six blocks were acquired through joint venture
operations. Holdings in the offshore Gulf of Mexico amounted to 701,764 gross
(260,232 net) acres at year-end compared to 606,581 gross (211,388 net) acres at
December 31, 1996. Ongoing acquisition of three-dimensional seismic data
continues to support the Company's exploration efforts.

Described below are the principal areas of Chieftain's activity in the Gulf of
Mexico. Production volumes shown are net to Chieftain, before royalties.

    WESTERN GULF (OFFSHORE TEXAS)

MATAGORDA ISLAND:

<TABLE>
<CAPTION>

               Blocks     Gross Acres     Net Acres     Average Interest     Average Production
               ------     -----------     ---------     ----------------     ------------------
<S>                       <C>             <C>           <C>                  <C>
                 9          47,610         16,635            34.9%               21.3 mmcfd
</TABLE>

This area has been a major source of the Company's production since 1989. Three
development wells were drilled during 1997, including two horizontal wells
drilled to delineate the 1996 discovery on Block 633 (Chieftain 25%). The third
well, also successful, was drilled on a separate fault block on 634 (Chieftain
24.1%). These wells contributed to a one-third increase in the Company's
production from the area. The reservoir underlying 634 is believed to extend to
the northeast where a drilling location has been selected. Three-dimensional
seismic data has been used to identify a deep prospect beneath the producing
reservoir on 634, and an exploratory well commenced drilling in early 1998.
Block 625 (Chieftain 25%), immediately north of Block 633, has been acquired to
protect the northern extension of the reservoir.

MUSTANG ISLAND:

<TABLE>
<CAPTION>
               Blocks     Gross Acres     Net Acres     Average Interest     Average Production
               ------     -----------     ---------     ----------------     ------------------
<S>                       <C>             <C>           <C>                  <C>
                 8          39,176         14,875             38%                 4.6 mmcfd
</TABLE>

Detailed seismic work and a 21,000-foot well are planned for 1998 on Block A-51
(Chieftain 25%) which was acquired at the August 1997 lease sale.

HIGH ISLAND:

<TABLE>
<CAPTION>

               Blocks     Gross Acres     Net Acres     Average Interest      Average Production
               ------     -----------     ---------     ----------------     --------------------
<S>                       <C>             <C>           <C>                  <C>
                 34         141,252        58,882             41.7%          9.5 mmcfd and 119 bd
</TABLE>

On Block 207 (Chieftain 50%), a platform will be installed for production to
commence in late 1998 from a 1996 gas discovery. The platform will also be used
to drill an exploratory prospect in the northeast corner of the block.

In the High Island South Addition area, eight blocks have been acquired in the
past two years. Active exploration of these holdings will begin with an
exploratory well on Block A-510 (Chieftain 50%) where drilling by a previous
leaseholder established pay in three wells which did not produce due to lack of
pipeline transportation. Access to pipelines is now readily available and
additional wells are planned for 1998.

                                        4
<PAGE>   5

    CENTRAL GULF (OFFSHORE LOUISIANA)

EAST CAMERON:

<TABLE>
<CAPTION>
          Blocks     Gross Acres     Net Acres     Average Interest     Average Production
          ------     -----------     ---------     ----------------     ------------------

<S>                  <C>             <C>           <C>                  <C>
            14          61,479        19,827             32.3%           1 mmcfd and 99 bd
</TABLE>

Major development work during 1997 resulted in the commencement of production,
in the fourth quarter of 1997, from Blocks 349, 350 and 356 (Chieftain 25%).
Production from four wells reached over 8 mmcfd and 700 bd, net to Chieftain,
prior to year-end. In late December this field was temporarily shut in for
repairs to a third-party pipeline. A fifth productive well was completed in
early 1998. Exploratory drilling is planned for Block 329 (Chieftain 33.3%).

VERMILION:

<TABLE>
<CAPTION>

          Blocks     Gross Acres     Net Acres     Average Interest     Average Production
          ------     -----------     ---------     ----------------     ------------------
<S>                  <C>             <C>           <C>                  <C>
             6          20,806        13,447            64.6%               0.4 mmcfd
</TABLE>

Production commenced in mid-year from a discovery well on Block 23 at
approximately one mmcfd, net to Chieftain's 25% interest. A successful follow-up
development well was drilled later in the year and will commence production in
early 1998. Exploratory wells are planned for Blocks 267, 368 and 16 (Chieftain
60%, 15% and 40%, respectively).

SOUTH MARSH ISLAND:

<TABLE>
<CAPTION>

          Blocks     Gross Acres     Net Acres     Average Interest     Average Production
          ------     -----------     ---------     ----------------     ------------------
<S>                  <C>             <C>           <C>                  <C>
            3          15,000          7,000             46.7%                 --
</TABLE>

A discovery well drilled on Block 39 (Chieftain 50%) at mid-year was followed up
by a second successful well late in 1997. New three-dimensional seismic data and
new interpretation techniques were utilized to identify prospects previously
shielded by a salt dome. The first well encountered 100 feet of sand containing
gas condensate. In the second well, the sand thickened to 245 feet of oil pay.
Short term production tests from the thicker pay section in the second well
flowed 850 bd of light gravity crude oil and associated gas. Potentially
productive deeper zones have not been tested. A third follow-up well was
drilling early in 1998. Additional exploratory follow-up wells are planned and
production is expected to commence in the last quarter of 1998. When fully
delineated, this field will likely prove to be Chieftain's largest 1997
discovery.

EUGENE ISLAND:

<TABLE>
<CAPTION>
          Blocks     Gross Acres     Net Acres     Average Interest     Average Production
          ------     -----------     ---------     ----------------     ------------------
<S>                  <C>             <C>           <C>                  <C>
            5          21,250          6,438             30.3%                 --
</TABLE>


On Block 83, Chieftain (40%) participated in a natural gas discovery.
Installation of a production platform was completed within four months and
production commenced early in 1998 at 4 mmcfd and 40 bd net to Chieftain. 

On Block 189 (Chieftain 75%), two successful oil and gas discoveries were
drilled on separate fault blocks. A follow-up well will be drilled on one of
these fault blocks and a third fault block remains to be drilled. Production is
expected to commence in late 1998.


                                        5

<PAGE>   6

    EASTERN GULF

MISSISSIPPI CANYON:

<TABLE>
<CAPTION>

          Blocks     Gross Acres     Net Acres     Average Interest     Average Production
          ------     -----------     ---------     ----------------     ------------------
<S>                  <C>             <C>           <C>                  <C>
            5          28,800          6,480             22.5%                0.1 mmcfd
</TABLE>

Early in 1998, drilling commenced on a deep water oil prospect on Block 29
(Chieftain 33.3%). The 7,500-foot well, on the flank of a salt dome, is being
drilled in 2,500 feet of water. Two other prospects have been identified on the
block and may be drilled after the first well. This acreage is in the deep water
Flex Trend adjacent to the Pompano oil field.

MAIN PASS:

<TABLE>
<CAPTION>
          Blocks     Gross Acres     Net Acres     Average Interest     Average Production
          ------     -----------     ---------     ----------------    ---------------------
<S>                  <C>             <C>           <C>                 <C>
            12         47,608          7,394             15.5%         10.5 mmcfd and 177 bd
</TABLE>

The two fields at Main Pass 223 (Chieftain 10%) and 225 (Chieftain 7%) were
among the largest industry discoveries on the Continental Shelf in 1995.
Subsequent drilling success added reserves and deliverability that surpassed the
capacity of the original pipeline to the area. Additional pipeline capacity is
being installed, necessitating the temporary shut-in of production. Production
from Block 217 (Chieftain 20%) is expected to commence in the second quarter of
1998. A new field was discovered in 1997 in the southern portion of Main Pass
250, in which Chieftain increased its interest from 7.5% to 20%. This field will
begin to produce by mid-1998. Three development wells are planned for Blocks 223
(Chieftain 10%) and 250 (Chieftain 20%).

MOBILE BAY:

<TABLE>
<CAPTION>
          Blocks     Gross Acres     Net Acres     Average Interest     Average Production
          ------     -----------     ---------     ----------------     ------------------
<S>                  <C>             <C>           <C>                  <C>
            3          17,138          6,409             37.4%               8.2 mmcfd
</TABLE>

A deep well to test a Norphlet sandstone gas prospect on Block 914 (Chieftain
18.75%) began drilling late in 1997. This well is being drilled at reduced cost
to Chieftain under a farm-out agreement with a major company. Total depth of
24,000 feet is expected to be reached during the second quarter of 1998.

    PARADOX BASIN, UTAH

ANETH UNIT:

<TABLE>
<CAPTION>
             Gross Acres     Net Acres     Average Interest     Average Production
             -----------     ---------     ----------------    ---------------------
<S>                          <C>           <C>                 <C>
                18,070         3,066            13.4%          0.23 mmcfd and 672 bd
</TABLE>

RATHERFORD UNIT:

<TABLE>
<CAPTION>
             Gross Acres     Net Acres     Average Interest      Average Production
             -----------     ---------     ----------------    ----------------------
<S>                          <C>           <C>                 <C>
                12,910         2,560          21.4%            0.4 mmcfd and 1,230 bd
</TABLE>

In the Four Corners area of southeastern Utah, Chieftain has interests in two
unitized oil fields, Aneth and Ratherford, where horizontal drilling has
improved the effectiveness of the waterflood enhanced recovery program,
resulting in cost-effective increases in recoverable reserves and production.
During 1997, oil production increased 7% in the Aneth Unit and 20% in the
Ratherford Unit. A total of 34 multi-lateral horizontal development wells were
drilled. In addition, a tertiary enhanced recovery pilot project is about to
commence at the Aneth Unit to further increase recoverability and production. A
similar


                                        6

<PAGE>   7

project is being considered for the Ratherford Unit. The horizontal drilling
program will continue with some 30 wells planned for the Units in 1998.

    NORTH SEA - UNITED KINGDOM SECTOR

<TABLE>
<CAPTION>
             Gross Acres     Net Acres     Average Interest          Average Production
             -----------     ---------     ----------------          ------------------
<S>                          <C>           <C>                       <C>
                73,993        12,731            17.2%                11 mmcfd and 41 bd
</TABLE>

Production during the fourth quarter from the Galahad (Chieftain 17.8%) and
Mordred (Chieftain 5.3%) fields averaged 15.5 mmcfd, net to Chieftain.
Production was shut in for several weeks at mid-year for maintenance work and in
the month of August, sales were suspended in response to low prices. Currently,
all of the gas, which is royalty free, flows to the United Kingdom. The U.K. is
Europe's largest gas market and recent deregulation has resulted in weak prices,
a situation which is expected to be temporary. The Interconnector pipeline from
England to Belgium is scheduled to be operational for the 1998-99 winter heating
season and will provide access for some North Sea production to higher priced
markets on the continent. The pipeline will have the capacity to supply 6% of
European demand.

    SIRTE BASIN

<TABLE>
<CAPTION>
             Gross Acres     Net Acres     Average Interest          Average Production
             -----------     ---------     ----------------          ------------------
<S>                          <C>           <C>                       <C>
              3,888,550       486,068           12.5%                        --
</TABLE>

A long term production test of three wells on NC-171 Block 5 in Libya began in
December 1997. Production was approximately 500 bd net to Chieftain's interest
in January 1998. The light, 31 degree gravity oil will be sold to European
refineries. If the production test determines commerciality, additional
development drilling and production facility upgrades will follow. Reserves have
not been booked as continuity of the reservoir will not be established until six
to twelve months of production testing has been completed. At that time, after
the recovery of certain costs, Chieftain's interest in the production will be
reduced. Under the terms of the concession agreement, Chieftain will participate
in two further exploratory wells.


                                        7

<PAGE>   8

ACREAGE

The following table summarizes the developed and undeveloped acreage held by
Chieftain as at December 31, 1997. Where applicable, interests which are not
working interests (none of which is material) have been converted to working
interest equivalents.

<TABLE>
<CAPTION>

                                    Developed Acres       Undeveloped Acres
Area                                Gross       Net       Gross        Net
-----------------------------       ------    ------    ---------    -------
<S>                                 <C>       <C>       <C>          <C>
United States
  Offshore Gulf of Mexico
   Louisiana                        21,909     6,744      313,577    101,557
   Texas                            14,082     3,883      343,424    145,478
   Texas State                         300        22        8,472      2,548
                                    ------    ------    ---------    -------
  Total Offshore Gulf of Mexico     36,291    10,649      665,473    249,583
                                    ------    ------    ---------    -------
  Onshore
   Louisiana                           573        72           --         --
   Montana                              --        --        3,240      3,240
   North Dakota                        997       227        3,185        188
   Pennsylvania                        324        36           --         --
   Texas                                --        --       13,357      3,339
   Utah                             29,860     4,895        1,120        731
                                    ------    ------    ---------    -------
  Total Onshore                     31,754     5,230       20,902      7,498
                                    ------    ------    ---------    -------

Total United States                 68,045    15,879      686,375    257,081
                                    ======    ======    =========    =======
United Kingdom
   North Sea                         7,584     1,348       66,409     11,383
                                    ======    ======    =========    =======

Libya
   Sirte Basin                          --        --    3,888,550    486,068
                                    ======    ======    =========    =======

Total, all areas                    75,629    17,227    4,641,334    754,532
                                    ======    ======    =========    =======
</TABLE>

Chieftain's developed and undeveloped acreage in all areas covered 4,716,963
gross (771,759 net) acres at December 31, 1997.

The undeveloped acreage has not been independently evaluated. The cost to
Chieftain thereof is approximately $41 million.


                                        8

<PAGE>   9

GAS AND OIL CAPITAL EXPENDITURES

The following table summarizes Chieftain's net capital expenditures for the
years ended December 31, 1997 and 1996.

<TABLE>
<CAPTION>

Year ended December 31,                1997        1996
-----------------------              -------    --------
<S>                                  <C>        <C>
(in thousands)
Property acquisition costs:
 United States                        $ 9,164    $ 13,954
 United Kingdom                           137         722
 Other foreign                             --          68
                                      -------    --------
                                        9,301      14,744
                                      -------    --------
Purchase of producing properties:
 United States                             --       2,077
                                      -------    --------

Sale of producing properties:
 United States                             --      (1,040)
                                      -------    --------

Exploration costs:
 United States                         35,540      17,453
 United Kingdom                           115          --
 Other foreign                          1,207         434
                                      -------    --------
                                       36,862      17,887
                                      -------    --------
Development costs:
 United States                         23,260      22,131
 United Kingdom                            30       1,874
                                      -------    --------
                                       23,290      24,005
                                      -------    --------
                                      $69,453    $ 57,673
                                      =======    ========
</TABLE>

DRILLING ACTIVITY

The following table summarizes the results of Chieftain's drilling activities
during the years ended December 31, 1997 and 1996.

<TABLE>
<CAPTION>
EXPLORATORY WELLS - Year ended December 31,             1997                  1996
                                                  Gross       Net       Gross       Net
                                                  -----       ----      -----       ----
<S>                                               <C>         <C>       <C>         <C>
Gas                                                   7       2.82          6       1.47
Oil                                                  --         --         --         --
Oil/Gas                                               1       0.50          1       0.25
Evaluating                                           --         --         --         --
Drilling at end of year                               3       0.94         --         --
Abandoned                                             9       2.99          8       2.26
                                                  -----       ----      -----       ----
                                                     20       7.25         15       3.98
                                                  =====       ====      =====       ====
</TABLE>

<TABLE>
<CAPTION>
DEVELOPMENT WELLS - Year ended December 31,              1997                 1996
                                                  Gross       Net       Gross       Net
                                                  -----       ----      -----       ----
<S>                                               <C>         <C>       <C>         <C>
Gas                                                   9       1.77          8       2.00
Oil                                                  34       6.15         20       3.00
Oil/Gas                                              --         --         --         --
Evaluating                                           --         --         --         --
Drilling at end of year                               4       0.81          5       0.80
Abandoned                                             1       0.50          2       0.67
                                                  -----       ----      -----       ----
                                                     48       9.23         35       6.47
                                                  =====       ====      =====       ====
</TABLE>

                                       9


<PAGE>   10

WELLS

Chieftain's productive gas and oil wells as at December 31, 1997 are listed in
the following table. Any interests which are not working interests (none of
which is material) have been converted to working interest equivalents.

<TABLE>
<CAPTION>
                                            Gas Wells             Oil Wells  
                                        Gross       Net       Gross       Net
                                        -----      -----      -----      -----
<S>                                     <C>        <C>        <C>        <C>
North Dakota                               --         --          2       0.47
Pennsylvania                                5       0.93         --         --
Utah                                       --         --        270      44.74
Louisiana                                   1       0.13         --         --
U.S. Gulf of Mexico                       109      27.59         15       4.45
United Kingdom                              3       0.41         --         --
                                        -----      -----      -----      -----
                                          118      29.06        287      49.66
                                        =====      =====      =====      =====
</TABLE>

In addition, Chieftain has interests in three (0.37 net) oil wells and one
suspended well in Libya. Three wells are currently undergoing production testing
to evaluate the feasibility of development.

RESERVES

Chieftain's gas and oil reserves have been evaluated by Netherland, Sewell &
Associates, Inc. ("NS&A") as to the U.S. reserves and by the Company as to the
U.K. reserves.

For estimates of the Company's proved and proved developed reserves see
"Supplementary Financial Information".

PRODUCTION VOLUMES, PRICES AND COSTS

Chieftain's net production of gas and oil (computed after royalty deductions but
before production taxes) for the years ended December 31, 1997 and 1996 is
listed below. Also listed are average sales prices and average production costs
during such periods.

<TABLE>
<CAPTION>
     Year ended December 31,               1997          1996
     -----------------------              ------        ------
<S>                                       <C>           <C>
     Total Net Production:
       Gas (mmcf)                         23,431        21,894
       Oil and liquids (mb)                  825           734
       Gas equivalent (mmcf)              28,383        26,296

     Average Daily Net Production:
       Gas (mmcf)                           64.2          59.8
       Oil and liquids (b) *               2,261         2,005
       Gas equivalent (mmcf)                77.8          71.8

     Average Sales Price:
       Gas (per mcf)                      $ 2.33        $ 2.09
       Oil and liquids (per b)            $18.94        $20.99

     Average Production Cost:
       Gas (per mcf)                      $ 0.27        $ 0.25
       Oil and liquids (per b)            $ 5.81        $ 6.57
</TABLE>

* Oil comprised approximately 83% of the oil and liquids over the periods shown.


                                       10

<PAGE>   11

MARKETING

Most of Chieftain's gas reserves are located in the Gulf of Mexico area of the
United States, where ready deliverability of gas through numerous large capacity
pipelines and auxiliary feeder pipelines provides flexibility in marketing
Chieftain's gas reserves in the U.S. spot market. Gas prices in the U.S. and in
the U.K. North Sea are largely determined by competitive market forces.

Most of the gas produced by Chieftain has been marketed since 1989 by Highland
Energy Company, an aggregator for several U.S. gas producers, at prices based on
spot market prices. Highland Energy Company has also represented Chieftain in
relation to the marketing of Chieftain's U.K. gas production.

Chieftain's oil production from the Aneth and Ratherford Units in the Four
Corners area of Utah has been sold under successive term contracts to a regional
refiner since 1989. The quantity and quality of this oil has obtained for
Chieftain premiums over locally posted prices. Most of Chieftain's Gulf of
Mexico oil and ngls production is marketed by Highland Energy Company.

Chieftain believes that alternative marketing arrangements would be readily
available for its gas,oil and liquids although no assurance can be given that
any alternative would not be less advantageous to Chieftain.

COMPETITION

There is competition in all aspects of the gas and oil industry, particularly
with respect to the marketing and sale of natural gas and oil production. There
is also competition for desirable exploratory, development and acquisition
prospects and for investment capital. Chieftain's competitors include the major
integrated oil companies as well as numerous independent gas and oil companies,
integrated gas production and transmission companies and other producers and
marketers of energy sources and fuels.

ENVIRONMENTAL REGULATION

Various laws and regulations covering the discharge of materials into the
environment, or otherwise relating to the protection of the environment, may
affect Chieftain's operations and costs. At present, Chieftain believes that its
properties are being operated in compliance with applicable environmental laws
and regulations. Chieftain does not anticipate that it will be required in the
foreseeable future to expend amounts that are unusual, in relation to customary
industry experience, by reason of environmental laws and regulations, but it is
unable to quantify the ultimate cost of compliance.

U.S. offshore oil and gas operations are subject to regulations of the United
States Department of the Interior which currently imposes absolute liability
upon the lessee under a federal lease for the cost of pollution clean-up
resulting from the lessee's operations, and could subject the lessee to possible
liability for pollution damages. In the event of a serious incident of
pollution, a lessee under a federal lease may be required to suspend or cease
operations in the affected area.

In the U.K., deposits of substances or articles at sea from offshore oil and gas
operations are subject to the licensing control of the Ministry of Agriculture,
Fisheries and Food. The breach of a license will result in criminal liability
and possible civil liability for the cost of any resulting pollution clean-up.
In the event of a serious incident of pollution, the Ministry may vary or revoke
a license.

REGULATION AND POLITICAL RISK

The gas and oil business is regulated by certain federal, state and local laws
and regulations relating to the development, marketing and transmission of gas
and oil, as well as taxation, environmental and safety matters. International
gas and oil operations, such as Chieftain's operations in the United Kingdom and
Libya, may also be subject to various regulatory,


                                       11

<PAGE>   12

political and economic factors. Political developments (especially in the Middle
East) and the decisions of OPEC (the Organization of Petroleum Exporting
Countries) can particularly affect world oil supply and oil prices. There is no
assurance that laws and regulations enacted in the future will not adversely
affect Chieftain's exploration for, or its production and marketing of, gas and
oil.

CONCENTRATION OF GAS PRODUCTION

Most of Chieftain's gas reserves and production are located offshore in the U.S.
Gulf of Mexico and could be adversely affected by natural disasters or market
conditions affecting this area.

DEVELOPMENT OF ADDITIONAL RESERVES

Chieftain's future success, as is generally the case in the industry, depends on
its ability to find or acquire additional gas oil reserves that are economically
recoverable. Except to the extent that Chieftain conducts successful exploration
or development activities or acquires properties containing proved reserves,
Chieftain's proved reserves will generally decline as reserves are produced.
There can be no assurance that Chieftain will be able to discover additional
commercial quantities of gas and oil or continue to acquire additional proved
properties.

EXPLORATION AND PRODUCTION RISKS

Gas and oil exploration involves a high degree of risk, which even a combination
of experience, knowledge and careful evaluation may not be able to overcome.
Chieftain's operations are subject to all of the risks normally incident to the
operation and development of gas and oil properties and the drilling of gas and
oil wells, including blowouts, cratering and fires and encountering unexpected
formations or pressures, which could result in personal injury,loss of life and
damage property of Chieftain and others. Offshore operations are subject to a
variety of special operating risks, such as hurricanes or other adverse weather
conditions, more extensive governmental regulation, including certain
regulations that may, in certain circumstances, impose absolute liability for
pollution damage, and interruption or termination by government authorities
based upon environmental or other considerations. In accordance with customary
industry practice, Chieftain may not be fully insured against these risks, nor
may all such risks be insurable.

PRICE UNCERTAINTY

There is uncertainty as to the prices at which gas and oil produced by Chieftain
may be sold, and it is possible that under some market conditions the production
of gas and oil from some of Chieftain's properties may not be commercially
feasible. The availability of a ready market for gas and oil as produced and the
price obtained for such gas and oil depend upon numerous factors beyond the
control of Chieftain, including market considerations, the proximity and
capacity of gas and oil pipelines and processing equipment and governmental
regulation. In recent years, markets for gas in the United States been
characterized by periods of oversupply relative to demand. There have been
significant fluctuations in prices for both gas and oil in recent years and
there can be no assurance that prices for gas or oil would not decrease in the
future.

EMPLOYEES

At December 31, 1997, Chieftain had 40 full-time equivalent employees. In
addition, Chieftain engages the services of consultants as required.


                                       12
<PAGE>   13

GLOSSARY

The following are defined terms used herein:

BARREL (b) means 34.972 Imperial gallons or 42 U.S. gallons.

BCF means 1,000,000,000 cubic feet.

BCFE means 1,000,000,000 cubic feet of gas equivalent.

BD means barrels per day.

BLOCK refers to an offshore Gulf Of Mexico gas and oil lease.

DEVELOPED ACREAGE refers to the number of acres assignable to productive wells.

DEVELOPMENT WELLS are wells drilled within the proved area of a gas or oil
reservoir to the depth of a stratigraphic horizon known to be productive.

DRY WELLS means wells found to be incapable of producing either gas or oil in
sufficient quantities to justify completion as gas or oil wells.

EXPLORATORY WELLS are wells drilled to find and produce gas or oil in an
unproved area, to find a new reservoir in a field previously found to be
productive of gas or oil in another reservoir, or to extend a known reservoir.

GAS means natural gas. Natural gas reserves are reported at a base pressure of
14.65 psia and a base temperature of 60 degrees Fahrenheit.

GAS EQUIVALENT is determined by using the approximate energy equivalent ratio of
6 mcf of gas to 1 b of oil and liquids.

GROSS ACRES means the total number of acres in which an interest is owned by
Chieftain.

GROSS WELLS means the total number of wells in which an interest is owned by
Chieftain.

LIQUIDS means natural gas liquids.

MB means 1,000 barrels.

MCF means 1,000 cubic feet.

MCFD means 1,000 cubic feet per day.

MMCF means 1,000,000 cubic feet.

MMCFD means 1,000,000 cubic feet per day.

MMCFE means 1,000,000 cubic feet of gas equivalent.

NET ACRES refers to the sum of the fractional interests owned in gross acres.

NET WELLS refers to the sum of the fractional interests owned in gross wells.

NGLS means natural gas liquids.

OIL OR OIL AND LIQUIDS means crude oil and natural gas liquids.

PRODUCTIVE WELLS are producing wells and wells capable of producing.


                                       13

<PAGE>   14

PROVED DEVELOPED PRODUCING RESERVES are those reserves which are expected to be
produced from existing completion intervals now open for production in existing
wells.

PROVED DEVELOPED NON-PRODUCING RESERVES are (1) those reserves expected to be
produced from existing completion intervals in existing wells, but due to
pending pipeline connections or other mechanical or contractual requirements
hydrocarbon sales have not yet commenced, and (2) other non-producing reserves
which exist behind the casing of existing wells, or at minor depths below the
present bottom of such wells, which are expected to be produced through these
wells in the predictable future, where the cost of making such oil and gas
available for production should be relatively small compared to the cost of a
new well.

PROVED RESERVES are the estimated quantities of natural gas, crude oil and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions. Proved reserves are limited to
those quantities of gas and oil which can be expected, with little doubt, to be
recoverable commercially at current prices and costs under existing regulatory
practices and with existing conventional equipment and operating methods.

PROVED UNDEVELOPED RESERVES are those reserves which are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion. Proved reserves on
undrilled acreage are limited to those drilling units offsetting productive
units that are reasonably certain of production when drilled.

UNDEVELOPED ACREAGE is acreage on which wells have not been drilled or completed
to a point that would permit the production of commercial quantities of gas and
oil regardless of whether or not such acreage contains proved reserves.

WORKING INTEREST refers to the net interest held by Chieftain in an oil or gas
lease or other disposition which interest bears its proportionate share of the
costs of exploration, development and operations and any royalties or other
production burdens.


                                       14

<PAGE>   15

ITEM 2.   PROPERTIES

Reference is made to Item 1, "Business", for information concerning the
materially important physical properties of Chieftain. In addition, Chieftain
leases office space.

ITEM 3.   LEGAL PROCEEDINGS

The Company and its subsidiaries are not party to, and none of its properties is
the subject of, any material legal proceeding.

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

No matters were submitted to a vote of security holders of the Company during
the fourth quarter of 1997.

EXECUTIVE OFFICERS OF THE REGISTRANT

The following table lists the name and age of each Executive Officer and all
positions and offices with the Company held by each such person. The officers
are appointed each year at the directors' meeting immediately following the
annual meeting of the shareholders. The next such meeting will be held on May
14, 1998.

<TABLE>
<CAPTION>
NAME                          AGE         POSITION/OFFICE
----                          ---         ---------------
<S>                           <C>        <C>
S.A. Milner, A.O.E.,LL.D.       69       Director, President and Chief Executive Officer
S.C. Hurley                     48       Director, Senior Vice President and Chief Operating Officer
E.L. Hahn                       60       Senior Vice President, Finance and Treasurer
E.S. Ondrack                    57       Director, Senior Vice President and Secretary
R.A. McDougall                  62       Vice President, Land
S.J. Milner                     40       Vice President, Drilling and Production
R.J. Stefure                    50       Controller
</TABLE>

With the following exceptions all of the officers have held positions as
officers of the Company since its incorporation in 1988, such position being his
or her principal occupation. S.C. Hurley joined Chieftain in September, 1995
prior to which time he was the Vice President Exploration of a U.S. based
integrated oil company. S.J. Milner and R.J. Stefure were appointed officers of
the Company in June, 1995 and prior thereto held management positions with the
Company.

There are no family relationships among the executive officers and directors
except between S.A. Milner and D.E. Mitchell, O.C. who are first cousins and
between S.A. Milner and S.J. Milner who are father and son.


                                       15

<PAGE>   16

                                     PART II

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

The principal United States market in which the Common Shares of the Company are
traded is the American Stock Exchange. The Common Shares are also traded on the
Toronto Stock Exchange. The high and low prices of the Chieftain International,
Inc. Common Shares (the "Common Shares") during each quarter since December 31,
1995 are shown below.

<TABLE>
<CAPTION>

                     Price History of Chieftain International, Inc. Common Shares
                         American Stock Exchange  The Toronto Stock Exchange
                              (U.S. dollars)          (Cdn. dollars)
                             High         Low        High         Low
                            ------      ------      ------      ------
<S>                         <C>         <C>         <C>         <C>
1996
  First quarter             $19.25      $15.75      $26.25      $21.25
  Second quarter             20.25       16.88       27.60       22.75
  Third Quarter              22.63       18.38       31.00       25.00
  Fourth Quarter             26.25       20.88       36.00       28.20

1997
  First quarter              25.88       18.63       35.40       26.00
  Second quarter             23.13       18.00       32.00       25.00
  Third quarter              27.37       20.50       37.65       28.35
  Fourth quarter             28.13       20.13       38.50       29.00

1998
  January                    21.38       17.94       30.25       25.60
  February                   23.25       19.88       33.25       28.75
  March 1 to March 13        23.94       21.81       33.90       31.00
</TABLE>

The Common Shares were held by 116 shareholders of record on December 31, 1997.
The Company estimates that investment dealers and other nominees hold Common
Shares for approximately 2,300 beneficial holders.

At the present time it is not the Company's policy to declare regular dividends
on the Common Shares. This policy is under periodic review by the Board of
Directors and is subject to change at any time depending on the earnings of the
Company and its financial requirements. Dividends may be paid on the Common
Shares provided that all dividends on the preferred shares of Chieftain
International Funding Corp. have been paid.

ITEM 6.   SELECTED CONSOLIDATED FINANCIAL DATA

The selected consolidated financial and operating data for each of the five
years ended December 31, 1997 has been derived from the consolidated financial
statements of the Company included herein and should be read in conjunction with
such consolidated financial statements and the related notes.

                                       16

<PAGE>   17

               SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA

                 CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARIES

<TABLE>
<CAPTION>
Year ended December 31,                                    1997            1996           1995             1994            1993
-----------------------                                    ----            ----           ----             ----            ----
<S>                                                     <C>            <C>            <C>              <C>             <C>
(in thousands except shares, per share amounts and
operating data)

INCOME STATEMENT DATA:
Revenue                                                 $    72,055    $    63,099    $     31,071     $     34,876    $     43,270
Direct expenses                                              11,569         10,707           8,181            7,443           7,149
Production taxes                                              1,756          1,513           1,382            1,396           1,305
General and administrative expenses                           4,308          3,972           3,346            3,402           2,921
Depletion and amortization (1)                               36,951         30,920          18,779           21,527          23,855
Additional depletion (2)                                         --             --              --           15,434              --
Income (loss) from operations, before dividends
 on preferred shares of a subsidiary                         10,160          9,784            (775)          (9,528)          4,883
Dividends on preferred shares of a subsidiary                 4,942          4,942           4,942            4,942           4,942
Net income (loss) applicable to common shares (1)             5,218          4,842          (5,717)         (14,470)            (59)
Net income (loss) per common share (1)                         0.38           0.37           (0.54)           (1.32)          (0.01)
Weighted average number of common shares outstanding     13,620,728     13,065,414      10,633,142       10,986,116      10,991,045

OTHER DATA:
Cash flow from operations                               $    49,473    $    41,841    $     13,186     $     17,647    $     26,894
Net gas and oil capital expenditures                    $    69,453    $    57,673    $    100,502     $     28,059    $     28,779

BALANCE SHEET DATA (at end of period):
Working capital                                         $    22,676    $    42,854    $     11,216     $    103,225    $    115,065
Total assets (1)                                        $   278,550    $   263,279    $    201,552     $    208,516    $    226,738
Long-term debt                                                   --             --              --               --              --
Shareholders' equity (1)                                $   186,063    $   180,719    $    127,131     $    137,351    $    152,754

OPERATING DATA:
Average Daily Net Production:
 Gas (mmcf)                                                    64.2           59.8            29.5             28.4            40.0
 Oil and liquids (b)                                          2,261          2,005           1,643            1,631           1,576
 Gas equivalent (mmcf)                                         77.8           71.8            39.3             38.2            49.5
Average Sales Price:
 Gas (per mcf)                                          $      2.33    $      2.09    $       1.54     $       1.97    $       2.05
 Oil and liquids (per b)                                      18.94          20.99           16.94            15.86           16.68
Average Production Cost:
 Gas (per mcf)                                          $      0.27    $      0.25    $       0.35     $       0.34    $       0.23
 Oil and liquids (per b)                                       5.81           6.57            7.31             6.79            6.56
</TABLE>

Notes:

(1)      Reference is made to Note 9 of the Notes to Consolidated Financial
         Statements which describes the impact of United States accounting
         principles.

(2)      This amount reflects write-downs in the carrying value of U.S. and
         Peruvian gas and oil properties in 1994 in accordance with full cost
         accounting rules under Canadian GAAP.

                                       17

<PAGE>   18

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

MANAGEMENT'S DISCUSSION AND ANALYSIS
To be read in conjunction with the 1997 audited consolidated financial
statements.

(Comparisons are with 1996 amounts unless otherwise stated)

The Company produces and sells natural gas and oil acquired through exploration
and development or through the purchase of producing properties. Producing
properties are held in the United States in the Gulf of Mexico and Utah; in the
British sector of the North Sea and in Libya. Exploration continues in these
areas.

In August 1995, the Company acquired 50% of the interests held by Santa Fe
Minerals, Inc. and affiliates in 57 offshore Gulf of Mexico blocks,
significantly increasing reserves, production and exploration acreage in this
area.

The Company continues to dedicate the majority of its attention and resources to
the U.S. Gulf of Mexico area and currently holds interests in 149 offshore lease
blocks upon which exploration or production operations are conducted.
Exploration offices in Dallas and New Orleans employ highly skilled technical
staff and leading-edge technology in the identification and delineation of gas
and oil prospects.

The Company's reporting currency is the U.S. dollar.

ANALYSIS OF OPERATING RESULTS

The 16% increase in production revenue resulted from an 11% increase in average
price received for natural gas to $2.33 per mcf, a 10% decrease in average oil
price received to $18.94 per barrel, an 8% increase in natural gas production
volumes to 28 bcf and a 12% increase in oil production volume to 962,000
barrels.

A $0.10 per mcf change in the average natural gas price received in 1997 would
have resulted in a change in revenue, cash flow and pre-tax income of $2.3
million. A $1.00 per barrel change in the average oil price would have resulted
in a change in revenue of $0.8 million and a change in cash flow and pre-tax
income of a slightly lesser amount.

U.S. production volumes of both oil and gas, particularly in late 1997, were
measurably constricted by delays in new pipeline construction. Such
constrictions continued through January 1998 and will affect first quarter
1998 accordingly. In Libya, production commenced in December 1997 from three
wells in the Sirte Basin. Six to twelve months of production testing is needed
to determine reserve quantities and the economics of additional drilling.

PRODUCTION AND PRICING

During 1997, Chieftain's production mix, on an energy equivalent basis, was 83%
natural gas and 17% oil and ngls. On a geographic basis, 88% of energy
equivalent production came from the United States. This ratio is expected to
remain fairly constant in 1998.

Chieftain has interests in 99 wells in the Gulf of Mexico of which 84 produce
gas and ngls and 15 produce oil. The largest increases in production during 1997
came from the Main Pass, Matagorda Island and East Cameron areas. In the North
Sea, three wells, one of which has two laterals, produce natural gas and ngls.

Oil production in 1997 came primarily from interests in 268 wells in the Aneth
and Ratherford Units located in southeast Utah. In 1998, growth in oil
production is expected to occur at the East Cameron 349 Field in the Gulf and
from production testing in the Sirte Basin in Libya. Oil is expected to comprise
approximately 25% of production on an energy equivalent basis in 1998.

                                       18


<PAGE>   19

At year-end, Chieftain was producing, before royalties, 62 mmcfd in the U.S., 14
mmcfd in the North Sea, 2000 bd from the Aneth and Ratherford Units in Utah and
800 bd from the Gulf. Gas production is expected to increase by over 10 mmcfd by
the end of the first quarter of 1998 as various production constraints are
alleviated. A production test of three wells in the Sirte Basin began at
year-end and by early January, the Company's share of production, until recovery
of certain costs, was approximately 500 bd with further increases expected
before production stabilizes.

Average annual gas prices were higher in 1997 than in the prior year.
Exceptionally strong pricing for gas from the Gulf of Mexico prevailed during
the winter months at the start of the year, and again in the August to November
period. The run up in prices during late summer was unexpected, but
deliverability data shows that there is very little excess gas supply in
Chieftain's primary markets. Gas prices in North America weakened at year-end
due to warm weather and higher than normal deliveries from storage which reduced
the spot demand for natural gas. Gas production contributed 76% of Company
revenue.

While the bulk of Chieftain's production is sold on a spot basis, some gas is
occasionally sold forward for near months. The Company has a positive view of
future prices, is reluctant to limit exposure to favorable price moves, and
therefore does not generally sell forward large quantities for extended periods
of time. In all cases, buyers take delivery. Chieftain does not engage in
speculative forward selling of volumes that cannot be physically delivered.

Higher rates of production are anticipated during 1998 as newly developed fields
are brought on stream.

Direct expenses and production taxes increased 8% and 16%, respectively,
generally in line with levels of production. During 1997, cost increases in the
Gulf reflected the high level of activity experienced by contractors. Direct
expenses, combined with production taxes, were maintained at the 1996 level of
$0.39 per mcfe. New volumes are, in many cases, being produced through existing
infrastructure, thereby contributing to overall efficiency and enhancing cash
flow and earnings. Chieftain's strategy is to concentrate its exploration
efforts in areas with nearby infrastructure, keeping facility costs low and
allowing early production.

General and administrative expense, up 8%, was also reflective of increased
production volumes.

Depletion and amortization expense increased 20%, the result of a 9% increase in
units of production and a 10% increase in average depletion rate to $1.08 per
gas equivalent unit.

CAPITAL RESOURCES AND LIQUIDITY

The table on this page summarizes cash provided from operating, financing and
investing activities for each of the past two years.

Cash generated from operating activities increased 37% primarily as a result of
higher operating revenue.

Financing activities in 1997 provided $0.1 million of cash, the net result of
the exercise of employee stock options for $1.0 million and the purchase of
36,300 common shares for cancellation for $0.9 million. In October 1997, the
Company announced a normal course issuer bid for up to 500,000 common shares. In
1996, the Company sold 2.97 million common shares for $46.6 million net of
issue costs and realized a further $1.1 million from the exercise of employee
stock options.

SOURCE AND USE OF CASH (US$ IN THOUSANDS)

<TABLE>
<CAPTION>

Year ended December 31,            1997         1996
-----------------------            ----         ----
<S>                             <C>          <C>
Cash provided from (used in):
 Operating activities           $ 50,489     $ 36,967
 Financing activities                126       47,657
 Investing activities            (66,139)     (52,750)
                                --------     --------
Increase (decrease) in cash     $(15,524)    $ 31,874
                                ========     ========
</TABLE>


                                       19

<PAGE>   20

Cash used in investing activities increased 25% to $66.1 million in 1997. The
Company participated in 68 wells of which seven were still drilling at year-end.
All of the 1997 wells were in the U.S. In 1996, the Company participated in 50
wells, 49 in the U.S. and one in the U.K. Industry activity levels were at a
peak in 1997, particularly in the Gulf of Mexico. Similarly high levels of
demand for drilling and services have resulted in cost increases and delays in
exploration and development programs. Recent declines in gas and oil prices are
expected to reduce such demand.

The December 31, 1997 cash balance of $26.9 million was down $15.5 million from
a year earlier. The Company has arranged a $100,000,000 revolving credit
facility with a syndicate of banks. Such facility was not drawn upon at December
31, 1997 and the Company remains debt-free.

OUTLOOK

While post-1997 price declines for natural gas and oil from year-earlier levels
indicate the possibility of lower average prices for 1998, higher production
volumes are anticipated which should result in steadily increasing cash flow
from operations.

The Board of Directors authorized an $85 million capital expenditure program for
1998 which is expected to be funded by cash flow from operations and working
capital. Such capital expenditures can be varied significantly with respect to
timing and priority dependent upon exploration success, availability of
equipment and services and current opportunities.

All of the Company's computer systems are year 2000 compliant.

ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The following consolidated financial statements of Chieftain International, Inc.
and the management's and auditors' reports thereon are included herein. The
financial statements are in U.S. dollars.

         Management's Report

         Auditors' Report

         Consolidated Balance Sheet as at December 31, 1997 and 1996

         Consolidated Statement of Income and Deficit for the years ended
         December 31, 1997, 1996 and 1995

         Consolidated Statement of Changes in Financial Position for the years
         ended December 31, 1997, 1996 and 1995

         Notes to Consolidated Financial Statements

         Supplementary Financial Information (Unaudited)

                                       20


<PAGE>   21

MANAGEMENT'S REPORT

February 4, 1998

The accompanying consolidated financial statements and all information in this
annual report are the responsibility of management. The financial statements
have been prepared by management in accordance with Canadian generally accepted
accounting principles. The financial information contained elsewhere in this
annual report is consistent with the consolidated financial statements in all
material respects.

The Company maintains accounting systems and internal controls to provide
reasonable assurance that its financial information is reliable and accurate,
and that its assets are adequately safeguarded. Where necessary, management has
made informed judgments and estimates in the preparation of the financial
statements.

Independent auditors, appointed by the shareholders, have examined the
consolidated financial statements. The Audit Committee of the Board of Directors
meets periodically with management and the independent auditors to review audit,
internal control, accounting policy and financial reporting matters.

The annual consolidated financial statements are approved by the Board of
Directors on the recommendation of the Audit Committee.

/s/ S.A. Milner                        /s/ E.L. Hahn
------------------------------------   -----------------------------------------
S.A. Milner                            E.L. Hahn
President and                          Senior Vice President,
Chief Executive Officer                Finance and Treasurer

AUDITORS' REPORT

To the Shareholders of Chieftain International, Inc.

We have audited the consolidated balance sheets of Chieftain International, Inc.
as at December 31, 1997 and 1996 and the consolidated statements of income and
deficit and changes in financial position for each of the years in the
three-year period ended December 31, 1997. 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 generally accepted auditing
standards. Those standards require that we plan and perform an audit to obtain
reasonable assurance 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.

In our opinion, these consolidated financial statements present fairly, in all
material respects, the financial position of the Company as at December 31, 1997
and 1996 and the results of its operations and the changes in its financial
position for each of the years in the three-year period ended December 31, 1997
in accordance with generally accepted accounting principles.

PRICE WATERHOUSE
--------------------------------
Chartered Accountants
Edmonton, Alberta

February 4, 1998

                                       21


<PAGE>   22

CONSOLIDATED BALANCE SHEET

<TABLE>
<CAPTION>
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES

(Full Cost Method of Accounting)
as at December 31,                                                              1997          1996
----------------------------------------------------------------------------------------------------
<S>                                                                          <C>           <C>
(US$ in thousands)

ASSETS

Current assets:
 Cash and short-term deposits                                                 $  26,925     $  42,449
 Accounts receivable                                                             10,862        11,199
 Other                                                                              606           293
                                                                              ---------     ---------
                                                                                 38,393        53,941
                                                                              ---------     ---------
Capital assets, at cost:
 Natural resource properties including exploration and development thereon      459,807       390,354
 Land and buildings                                                                 200           200
 Other equipment                                                                  1,847         1,589
                                                                              ---------     ---------
                                                                                461,854       392,143
 Less: Accumulated depletion and amortization                                   225,139       188,254
                                                                              ---------     ---------
                                                                                236,715       203,889
                                                                              ---------     ---------

Deferred income taxes                                                             3,442         5,449
                                                                              ---------     ---------

                                                                              $ 278,550     $ 263,279
                                                                              =========     =========
LIABILITIES AND SHAREHOLDERS' EQUITY

Current liabilities:
 Accounts payable and accrued                                                $  15,717     $  11,087

Deferred income taxes                                                           13,367         8,070

Preferred shares of a subsidiary (Note 3)                                       63,403        63,403

Shareholders' equity (Note 4):
 Share capital --
  Authorized -- an unlimited number of --
   First preferred shares
   Second preferred shares
   Common shares
  Issued --
   13,622,375 common shares (1996 -- 13,591,763)                               192,845       192,381
 Contributed surplus                                                               307           645
 Deficit                                                                        (7,089)      (12,307)
                                                                             ---------     ---------
                                                                               186,063       180,719
                                                                             ---------     ---------

                                                                             $ 278,550     $ 263,279
                                                                             =========     =========
</TABLE>

Approved by the Board:

/s/ S.A. Milner              /s/ L.G. Munin
-----------------------     ------------------------------
S.A. Milner, Director        L.G. Munin, Director


                                       22


<PAGE>   23

CONSOLIDATED STATEMENT OF INCOME AND DEFICIT

CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES

<TABLE>
<CAPTION>
Year ended December 31,                                     1997              1996             1995
--------------------------------------------------------------------------------------------------------
<S>                                                     <C>              <C>              <C>
(US$ in thousands except shares and per share amounts)

Production revenue                                      $     84,219     $     72,838     $     31,733
 Less: Royalties                                              14,592           12,226            5,058
                                                        ------------     ------------     ------------
Production revenue, net of royalties                          69,627           60,612           26,675
Interest and other revenue                                     2,428            2,487            4,396
                                                        ------------     ------------     ------------
                                                              72,055           63,099           31,071
                                                        ------------     ------------     ------------

Direct expenses                                               11,569           10,707            8,181
Production taxes                                               1,756            1,513            1,382
General and administrative expenses                            4,308            3,972            3,346
Depletion and amortization                                    36,951           30,920           18,779
                                                        ------------     ------------     ------------
                                                              54,584           47,112           31,688
                                                        ------------     ------------     ------------
Income (loss) before income taxes and dividends on
 preferred shares of a subsidiary                             17,471           15,987             (617)

Income taxes (Note 5):
 Current                                                           7              124               34
 Deferred                                                      7,304            6,079              124
                                                        ------------     ------------     ------------
                                                               7,311            6,203              158
                                                        ------------     ------------     ------------

Income (loss) before dividends on preferred shares
 of a subsidiary                                              10,160            9,784             (775)

Dividends paid on preferred shares of a subsidiary             4,942            4,942            4,942
                                                        ------------     ------------     ------------

Net income (loss) applicable to common shares                  5,218            4,842           (5,717)

Deficit, beginning of year                                   (12,307)         (17,149)         (11,432)
                                                        ------------     ------------     ------------

Deficit, end of year                                    $     (7,089)    $    (12,307)    $    (17,149)
                                                        ============     ============     ============
Net income (loss) per common share (Note 6)             $       0.38     $       0.37     $      (0.54)
                                                        ============     ============     ============

Weighted average number of common shares outstanding      13,620,728       13,065,414       10,633,142
                                                        ============     ============     ============
</TABLE>


                                       23

<PAGE>   24

CONSOLIDATED STATEMENT OF CHANGES IN FINANCIAL POSITION

CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES

<TABLE>
<CAPTION>
Year ended December 31,                                   1997          1996          1995
-----------------------------------------------------------------------------------------------
<S>                                                     <C>          <C>           <C>
(US$ in thousands)

Operating activities:
 Net income (loss) applicable to common shares          $  5,218     $   4,842     $  (5,717)
 Items not requiring a current cash outlay:
  Depletion and amortization                              36,951        30,920        18,779
  Deferred income taxes                                    7,304         6,079           124
                                                        --------     ---------     ---------
 Cash flow from operations                                49,473        41,841        13,186
 Change in non-cash operating working capital
  Accounts receivable                                        337        (2,936)       (2,879)
  Other current assets                                      (313)          199          (112)
  Accounts payable and accrued                               992          (901)          921
  Dividend payable                                            --        (1,236)        1,236
                                                        --------     ---------     ---------
                                                          50,489        36,967        12,352
                                                        --------     ---------     ---------

Financing activities:
 Issue of common shares                                      975        50,097            40
 Purchase of common shares for cancellation                 (849)           --        (4,543)
 Financing costs                                              --        (2,440)           --
                                                        --------     ---------     ---------
                                                             126        47,657        (4,503)
                                                        --------     ---------     ---------

Investing activities:
 Lease acquisition, exploration and development costs    (69,453)      (56,636)      (45,824)
 Purchase of producing gas and oil properties                 --        (2,077)      (54,678)
 Sale of producing properties                                 --         1,040            --
                                                        --------     ---------     ---------
                                                         (69,453)      (57,673)     (100,502)
 Purchase of other capital assets                           (324)         (187)         (190)
 Change in investing accounts payable and accrued          3,638         5,110         1,267
                                                        --------     ---------     ---------
                                                         (66,139)      (52,750)      (99,425)
                                                        --------     ---------     ---------

Change in cash and short-term deposits                   (15,524)       31,874       (91,576)

Cash and short-term deposits, beginning of year           42,449        10,575       102,151
                                                        --------     ---------     ---------

Cash and short-term deposits, end of year               $ 26,925     $  42,449     $  10,575
                                                        ========     =========     =========
</TABLE>


                                       24

<PAGE>   25

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DECEMBER 31, 1997, 1996 AND 1995)

CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES

The Company is engaged in gas and oil exploration, development and production
primarily in the United States and also in the U.K. sector of the North Sea and
in Libya. The Consolidated Financial Statements are expressed in United States
currency as most of the Company's assets and operations are denominated in U.S.
dollars.

 1. Summary of Significant Accounting Policies

   (a) ACCOUNTING PRINCIPLES

       The Company's financial statements are prepared in conformity with
       Canadian generally accepted accounting principles. The preparation of
       financial statements in conformity with generally accepted accounting
       principles requires management to make informed judgements and estimates.
       Actual results may differ from those estimates. Material differences
       between Canadian and U.S. accounting principles that affect the Company
       are referred to in Note 9, which provides details of the effect of such
       differences on earnings and balance sheet accounts.

   (b) PRINCIPLES OF CONSOLIDATION

       The Consolidated Financial Statements include the accounts of the Company
       and its subsidiary companies, all of which are wholly-owned except for
       Chieftain International Funding Corp., a U.S. subsidiary which in
       1992 issued 2,726,700 preferred shares to the public. These preferred
       shares are convertible into common shares of Chieftain International,
       Inc. See Note 3.

       Acquisitions of subsidiaries and businesses have been accounted for by
       the purchase method and accordingly only income or losses since date of
       acquisition are included in the Consolidated Statement of Income.

   (c) FOREIGN CURRENCY TRANSLATION

       Canadian and other foreign currency amounts have been translated into
       U.S. currency on the following bases: monetary assets and liabilities at
       the year-end rates of exchange; non-monetary assets and liabilities at
       historical exchange rates; and revenue and expenses at monthly average
       exchange rates during the year. Translation gains or losses are reflected
       in the Consolidated Statement of Income.

   (d) FINANCIAL ASSETS AND LIABILITIES

       The Company's financial instruments that are included in the Consolidated
       Balance Sheet are comprised of cash and short-term deposits, accounts
       receivable and all current liabilities, the fair values of which
       approximate their carrying amounts due to their short-term nature. Cash
       and short-term deposits include minimum risk certificates guaranteed by a
       major Canadian bank and are purchased three months or less from maturity.
       Accounts receivable are subject to normal oil and gas industry credit
       risks.


                                       25

<PAGE>   26

   (e) NATURAL RESOURCE PROPERTIES

       The Company accounts for gas and oil properties in accordance with
       Canadian guidelines on full cost accounting.

       Under this method, all costs associated with the acquisition, exploration
       and development of gas and oil properties are capitalized in cost centers
       on a country-by-country basis. A ceiling test is applied to ensure that
       capitalized costs do not exceed estimated future net revenues less
       applicable costs. Depletion is calculated using the unit-of-production
       method based on gross proved reserves before royalties and combining oil
       and natural gas on an energy equivalent basis. Future well abandonment
       and site restoration costs are included in the calculation of depletion
       expense.

       The following weighted average field prices were used in the
       determination of the Company's U.S. future net revenues for purposes of
       the ceiling test:

<TABLE>
<CAPTION>
As at December 31,                                1997      1996      1995
-----------------------------------------------------------------------------
<S>                                              <C>       <C>       <C>
Oil - per barrel                                 $16.92    $24.29    $18.71
                                                 ==========================
Ngls - per barrel                                $15.14    $21.66    $16.64
                                                 ==========================
Oil & ngls - per barrel                          $16.69    $24.03    $18.48
                                                 ==========================
Natural gas - per thousand cubic feet ("mcf")    $ 2.74    $ 3.43    $ 2.06
                                                 ==========================
</TABLE>

       A field price of $1.76 (1996 - $2.04; 1995 - $0.86) per thousand cubic
       feet was used in the determination of the Company's U.K. future net
       revenues for purposes of the ceiling test.

       Depletion rates per physical unit of U.S. production are as follows:

<TABLE>
<S>                                   <C>             <C>
Year ended December 31, 1995          $ 1.10          $ 6.57
                                      ======================
Year ended December 31, 1996          $ 1.03          $ 6.16
                                      ======================
Year ended December 31, 1997          $ 1.11          $ 6.68
                                      ======================
</TABLE>

       The depletion rate per physical unit of U.K. natural gas production was
       $0.81 per mcf for the year ended December 31, 1997 (1996 - $0.56; 1995 -
       $0.53).

       Libyan property carrying costs of $14.6 million at December 31, 1997 are
       excluded from depletion calculations pending determination of reserves.

       General and administrative costs relating directly to lease acquisition,
       exploration and development activities have been capitalized as follows:

<TABLE>
<CAPTION>
Year ended December 31,                           1997      1996      1995
----------------------------------------------------------------------------
(In thousands)
<S>                                              <C>       <C>       <C>
Lease acquisition                                $  694    $  837    $  538
Exploration                                       1,470     1,547     1,909
Development                                       1,387     1,254       928
                                                 --------------------------
                                                 $3,551    $3,638    $3,375
                                                 ==========================
</TABLE>
                                                 

                                       26

<PAGE>   27

   (f) LAND, BUILDINGS AND OTHER EQUIPMENT

       Amortization is provided as follows:

<TABLE>
<CAPTION>
                                                            Rate per
                                                              annum               Method
--------------------------------------------------------------------------------------------
<S>                                                         <C>                <C>
Buildings                                                          5%          Straight-line
Furniture, office equipment and leasehold improvements       10 - 20%          Straight-line
</TABLE>

       Expenditures for renewals and betterments which materially increase the
       estimated useful life of buildings and equipment are capitalized;
       expenditures for repairs and maintenance are charged to income. Costs and
       accumulated amortization of assets retired or sold are removed from the
       asset and related accumulated amortization accounts; losses and gains
       thereon are included in the Consolidated Statement of Income as depletion
       and amortization.

   (g) INCOME TAXES

       The Company follows the tax allocation method of accounting for the tax
       effect of all timing differences between taxable income and accounting
       income. Thus, provision is made currently for taxes deferred as a result
       of claiming for tax purposes deductions in excess of amounts charged to
       income in the books, principally natural resource lease acquisition
       costs, intangible exploration, development and drilling costs and costs
       of tangible capital assets.

2. Revolving Credit and Term Loan Arrangements

   In 1997 the Company arranged an unsecured revolving credit facility with a
   syndicate of banks. The facility, in the amount of U.S. $100 million or
   Canadian dollar equivalents, is fully revolving for 364 day periods with
   extensions at the option of the lenders upon notice from the Company. If not
   extended, the facility converts to term loans repayable over a period not
   exceeding four years. Advances under the facility bear interest at Canadian
   prime or U.S. base rate, or at Bankers' Acceptance rates or LIBOR plus
   applicable margins. No amounts had been advanced under this facility at
   December 31, 1997.

3. Preferred Shares of a Subsidiary

   Chieftain International Funding Corp. ("Funding"), a subsidiary of Chieftain
   International (U.S.) Inc., sold 2,726,700 shares of $1.8125 cumulative
   convertible redeemable preferred shares at $25.00 per share in a 1992
   public offering in the United States. The preferred shares are redeemable, at
   the option of Funding, at $25.8056 per share during 1998, declining to $25.00
   per share after December 31, 2001, plus accumulated and unpaid dividends.
   Each preferred share has a liquidation preference of $25.00 and is
   convertible at any time into 1.25 Common Shares of Chieftain International,
   Inc. at the option of the holder.


                                       27

<PAGE>   28

4. Shareholders' Equity

   (a) COMMON SHARES

<TABLE>
<CAPTION>
Year ended December 31,                         1997                         1996                           1995
---------------------------------------------------------------------------------------------------------------------------
(dollars in thousands)                  Number        Share          Number       Share             Number        Share
                                        of            Capital        of           Capital           of            Capital
                                        shares        Account        shares       Account           shares        Account
---------------------------------------------------------------------------------------------------------------------------
<S>                                   <C>            <C>           <C>           <C>              <C>            <C>
Balance, beginning of year            13,591,763     $ 192,381     10,546,100    $143,635         10,912,100     $ 148,621
Share options exercised                   66,912           975         75,663       1,092              3,000            40
Shares purchased and cancelled*          (36,300)         (511)            --          --           (369,000)       (5,026)
Shares issued for cash                        --            --      2,970,000      47,654**             --            --
                                     --------------------------------------------------------------------------------------
Balance, end of year                  13,622,375     $ 192,845     13,591,763    $192,381         10,546,100     $ 143,635
                                     ======================================================================================
</TABLE>
                                     
 * Pursuant to normal course issuer bid.
** Reduced by costs of issue of $2,440, less related deferred taxes of $1,089.

       In the first quarter of 1996, the Company sold 2,970,000 common shares,
       by way of a public offering in the United States and Canada, at $16.50 
       per share (C$22.75).

   (b) COMMON SHARES RESERVED

       At December 31, 1997 a total of 1,159,091 (1996 - 1,226,003; 1995 -
       1,046,250) of the authorized but unissued common shares of the Company
       were reserved for issuance under the Share Option Plan. See Note 4(d).

       The Company has reserved 3,408,375 common shares for issuance pursuant to
       the conversion provisions of the preferred shares of a subsidiary. See
       Note 3.

   (c) CONTRIBUTED SURPLUS

       Contributed surplus represents the excess of original net issue price
       over purchase price of shares purchased and cancelled pursuant to issuer
       bids in 1995 and 1997.

   (d) SHARE OPTION PLAN (THE "PLAN")

       The Plan provides for the granting of options to employees, directors and
       consultants to purchase common shares of the Company. In 1996, the number
       of shares reserved for issuance under the plan was increased by 255,416
       (1995 - 154,250). Each option expires not later than ten years from the
       date it was granted. The exercise of options granted under the Plan is
       contingent upon continued service except that options which are
       exercisable may be exercised after termination of service under certain
       conditions. Options granted are exercisable as to one-third of the
       granted amount on or after each of the first three anniversaries of the
       date of grant or over such longer period as may be determined by the
       directors. Exercisability of options accelerates in certain events. The
       option price for shares in respect of which an option is granted under
       the Plan is not less than the market price on the date of grant.


                                       28

<PAGE>   29

At December 31, 1997 the following options were outstanding to 50 participants
in the Plan:

<TABLE>
<CAPTION>
                 Option Price Per
   Shares             Share         Year of Expiry
---------------------------------------------------
<S>              <C>                <C>
   125,000       $13.50                1999
    15,000        14.50 -- 16.10       1999
    70,000        19.00                2001
    30,334        20.12 -- 20.87       2003
   230,534        15.38                2004
   347,805        13.63 -- 15.63       2005
    15,000        23.75                2006
   224,000        19.87 -- 22.50       2007
</TABLE>

The following is a summary of activity related to the Plan for the years ended
December 31, 1997, 1996 and 1995.

<TABLE>
<CAPTION>
                                       Number
                                       of               Minimum Option Price             Market Value at Date Granted
                                       Shares        Per Share           Total           Per Share             Total
-----------------------------------------------------------------------------------------------------------------------
<S>                                    <C>         <C>                <C>              <C>                <C>
Outstanding December 31, 1994          607,250     $13.50 -- 20.87    $  9,404,075     $13.50 -- 20.87    $  9,456,875

Year ended December 31,1995
  Granted                              384,000      13.63 -- 15.63       5,365,420      13.63 -- 15.63       5,365,420
  Exercised                             (3,000)     13.50                  (40,500)     13.50                  (40,500)
  Forfeited                             (8,000)     15.38                 (123,040)     15.38                 (123,040)
                                      --------                         -----------                          ---------- 
Outstanding December 31, 1995          980,250                          14,605,955                          14,658,755

Year ended December 31,1996
  Granted                               15,000      23.75                  356,250      23.75                  356,250
  Exercised                            (75,663)     13.50 -- 16.25      (1,075,572)     13.50 -- 16.25      (1,097,972)
  Forfeited                            (10,334)     13.63 -- 20.12        (159,079)     13.63 -- 20.12        (159,079)
                                      --------                         -----------                         -----------
Outstanding December 31, 1996          909,253                          13,727,554                          13,757,954

Year ended December 31,1997
  Granted                              228,000      19.87 -- 22.50       4,866,690      19.87 -- 22.50       4,866,690
  Exercised                            (66,912)     13.50 -- 20.87        (968,548)     13.50 -- 20.87        (974,948)
  Forfeited                            (12,668)     13.63 -- 21.32        (203,425)     13.63 -- 21.32        (203,425)
                                     ---------                        ------------                        ------------
Outstanding December 31, 1997        1,057,673                        $ 17,422,271                        $ 17,446,271
                                     =========                        ============                        ============

Exercisable at December 31, 1995       404,583     $13.50 -- 20.87    $  6,227,813
                                    ==========                        ============
Exercisable at December 31, 1996       558,319     $13.50 -- 20.87    $  8,548,461
                                    ==========                        ============
Exercisable at December 31, 1997       707,738     $13.50 -- 23.75    $ 10,777,986
                                    ==========                        ============
</TABLE>


                                       29

<PAGE>   30

5. Income Taxes

   Income tax expense is made up of the following components:

<TABLE>
<CAPTION>
Year ended December 31,                                  1997                 1996                1995
-------------------------------------------------------------------------------------------------------------
(in thousands)                                     Canada      U.S.     Canada      U.S.     Canada     U.S.
-------------------------------------------------------------------------------------------------------------
<S>                                                <C>       <C>        <C>       <C>        <C>       <C>
Income (loss) before income taxes and dividends
  on preferred shares of a subsidiary              $2,072    $15,399    $1,461    $14,526    $(324)    $(293)
                                                   ------    -------    ------    -------    -----     -----
Income taxes (recovery)
  Current                                               7         --       124         --       34        --
  Deferred                                          2,007      5,297       912      5,167      292      (168)
                                                   ------    -------    ------    -------    -----     -----
                                                   $2,014    $ 5,297    $1,036    $ 5,167    $ 326     $(168)
                                                   ======    =======    ======    =======    =====     =====
</TABLE>

Deferred income tax expense results from timing differences between the
recognition of expenses for tax and financial statement purposes as explained in
Note 1(g). The sources of these differences are as follows:

<TABLE>
<CAPTION>
Year ended December 31,                             1997                   1996                    1995
----------------------------------------------------------------------------------------------------------------
(in thousands)                               Canada       U.S.       Canada       U.S.       Canada       U.S.
----------------------------------------------------------------------------------------------------------------
<S>                                         <C>         <C>         <C>         <C>         <C>         <C>
Amortization of buildings and equipment     $  (112)    $  (275)    $     3     $   340     $   136     $    11
Depletion of natural resource properties        (68)      6,011         805       5,898       1,289       6,567
Financing costs                                 338          --         348          --         129          --
Tax loss carry forward                        1,846        (430)       (230)     (1,143)     (1,206)     (6,746)
Other                                             3          (9)        (14)         72         (56)         --
                                            -------     -------     -------     -------     -------     -------
                                            $ 2,007     $ 5,297     $   912     $ 5,167     $   292     $  (168)
                                            =======     =======     =======     =======     =======     =======
</TABLE>

The actual tax rate differs from the expected tax rate for the following
reasons:

<TABLE>
<CAPTION>
Year ended December 31,                                       1997      1996      1995
----------------------------------------------------------------------------------------
<S>                                                           <C>       <C>       <C>
Expected percentage on pre-tax income (loss)
  (Combined Canadian federal and provincial rate)             44.6%     44.6%     44.6%
Add (deduct) the effect of:
  Lower income tax rate on earnings of U.S. subsidiaries      (7.9)     (7.9)     (7.4)
  Canadian income tax on exchange loss (gain) which is
    eliminated upon consolidation                                2.1    (0.3)    (63.8)
  Other                                                        3.0       2.4       1.0
                                                              ----      ----     -----
Actual percentage of income tax on pre-tax income (loss)      41.8%     38.8%    (25.6)%
                                                              ====      ====     =====
</TABLE>


                                       30

<PAGE>   31

6. Per Share Amounts

   Net income (loss) per common share is computed by dividing net income (loss)
   applicable to common shares by the weighted average number of common shares
   outstanding during the year.

   In the calculation of fully diluted earnings per share, shares outstanding
   are adjusted for share options and shares issuable on conversion of preferred
   shares. Earnings are adjusted by the amount of imputed interest on share
   option proceeds and preferred share dividends. Earnings were not diluted
   during the periods shown.

7. Pension Costs and Obligations

   The Company contributed $144,254, $103,455 and $73,230 for 1997, 1996 and
   1995, respectively, to defined contribution plans. Under a supplementary
   defined contribution plan established in 1991, costs of $162,384, $127,358
   and $97,299 for 1997, 1996 and 1995, respectively, and the related liability
   are recorded in the accounts but are not currently funded.

   The Company has established no other retirement benefit plans.

8. Segment Information

<TABLE>
<CAPTION>
                                                    1997          1996          1995
--------------------------------------------------------------------------------------
<S>                                              <C>           <C>           <C>
(In thousands)

Industry segments --
The company operates in one industry segment.
Production revenues included below are net
of royalties.

Geographic segments --
Revenue:
  United States                                  $  63,498     $  56,827     $  26,674
  United Kingdom                                     6,231         4,155           552
  Corporate and other                                2,326         2,117         3,845
                                                 ---------     ---------     ---------
                                                 $  72,055     $  63,099     $  31,071
                                                 =========     =========     =========
Income (loss) before income taxes and
dividends on preferred shares of a subsidiary
  United States                                  $  14,569     $  14,173     $  (3,461)
  United Kingdom                                     1,613         1,102           129
  Peru                                                 (14)          (19)         (225)
  Corporate and other                                1,303           731         2,940
                                                 ---------     ---------     ---------
                                                 $  17,471     $  15,987     $    (617)
                                                 =========     =========     =========
Identifiable assets:
  United States                                  $ 227,461     $ 185,974     $ 159,564
  United Kingdom                                    15,324        18,613        17,048
  Libya                                             14,642        13,322        13,107
  Corporate and other                               21,123        45,370        11,833
                                                 ---------     ---------     ---------
                                                 $ 278,550     $ 263,279     $ 201,552
                                                 =========     =========     =========
</TABLE>


                                       31

<PAGE>   32

9. United States Accounting Principles

   U.S. full cost accounting rules differ materially from the Canadian full cost
   accounting guidelines followed by the Company. In determining the limitation
   on carrying values, U.S. rules require the discounting of future net revenues
   at 10%, and Canadian guidelines require the use of undiscounted future net
   revenues and the deduction of estimated future administrative costs. During
   1995 an impairment adjustment would have been required under U.S. accounting
   rules. The test required by U.S. accounting rules, using a December 31, 1995
   U.K. gas price of $0.86 per mcf to determine future net revenues, would have
   resulted in a write-down of U.K. property carrying costs of $3.8 million,
   after providing for tax recoveries of $2.9 million, at December 31, 1995.

   The effect on the Consolidated Balance Sheet of the differences between
   Canadian and U.S. accounting principles is as follows:

<TABLE>
<CAPTION>
As at December 31,                     1997                       1996
-----------------------------------------------------------------------------------
(in thousands)
                                            Under U.S.                 Under U.S.
                                           Accounting                  Accounting
                            As Reported    Principles   As Reported    Principles
-----------------------------------------------------------------------------------
<S>                         <C>            <C>          <C>            <C>
Net capital assets           $ 236,715     $ 218,673     $ 203,889     $ 182,670
Deferred tax -- asset        $   3,442     $   5,537     $   5,449     $   7,660
Deferred tax -- liability    $  13,367     $   8,737     $   8,070     $   2,671
Deficit                      $  (7,089)    $ (18,406)    $ (12,307)    $ (25,916)
</TABLE>

The effect on consolidated earnings of these differences is summarized as
follows:

<TABLE>
<CAPTION>
Year ended December 31,                                                                1997             1996             1995
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                                                               <C>              <C>              <C>
(In thousands except shares and per share amounts)

Net income (loss) applicable to common shares, as reported                        $      5,218     $      4,842     $     (5,717)
Additional depletion                                                                        --               --           (6,740)
                                                                                  ------------     ------------     -------------
                                                                                         5,218            4,842          (12,457)
Reduction in depletion expense                                                           3,177            2,381            2,775
Reduction (increase) in deferred tax provision                                            (885)          (1,021)           1,820
                                                                                  ------------     ------------     -------------
Net income (loss) applicable to common shares under U.S. accounting principles    $      7,510     $      6,202     $     (7,862)
                                                                                  ============     ============     =============
Net income (loss) per common share under U.S. accounting principles:
  Basic                                                                           $       0.55     $       0.47     $      (0.74)
                                                                                  ============     ============     =============
  Fully diluted                                                                   $       0.54     $       0.46     $      (0.74)
                                                                                  ============     ============     =============
Fully diluted number of common shares outstanding                                   13,858,593       13,446,684       10,633,142
                                                                                  ============     ============     =============
</TABLE>


                                       32

<PAGE>   33

Effective for 1997, U.S. accounting principles exclude common share equivalents
in determining basic earnings per common share. Share options are included in
fully diluted earnings (loss) per common share, where dilutive, assuming all
share options are exercised using the treasury stock method. The comparative per
share amounts have been restated to reflect the revised accounting principles.

The Company applies the intrinsic value method prescribed by APB opinion 25 and
related interpretations in accounting for share option transactions.
Accordingly, no compensation cost is recognized in the accounts. U.S. accounting
principles require disclosure of the impact on earnings and earnings per share
of the value of options granted after 1994, calculated in accordance with FAS
123. Such impact, calculated using the Black-Scholes option pricing model,
applying risk-free interest rates of 6.85% for 1997, 6.51% for 1996 and 6.40%
for 1995 and assuming ten year expected option lives, no dividend yields and
expected volatilities of 24% for all three years on a weighted average basis,
would amount to a net of tax charge to income (loss) of $1,348,000 (1996 -
$872,000; 1995 - $270,000). After reflecting this charge, pro forma net income
(loss) applicable to common shares under U.S. accounting principles would be
$6,162,000, (1996 - $5,330,000; 1995 - $(8,132,000)); pro forma net income
(loss) per common share under U.S. accounting principles would be $0.45 (1996 -
$0.41; 1995 - $(0.76)); and pro forma fully diluted earnings (loss) per common
share under U.S. accounting principles would be $0.45 (1996 - $0.40; 1995 -
$(0.76)). These effects are not necessarily indicative of those to be expected
in future years.

U.S. accounting principles require corporations to account for deferred income
taxes by the liability method. The effect on the Company of the application of
such method is not material.

Deferred tax assets (liabilities) are comprised of the following:

<TABLE>
<CAPTION>
As at December 31,                         1997          1996
---------------------------------------------------------------
(In thousands)

<S>                                      <C>          <C>
Deferred tax assets
  Depletion and amortization             $  3,413     $  3,735
  Financing costs                             633          965
  Loss carry forwards                      14,908       16,092
  Other                                       346          261
                                         ---------------------
                                           19,300       21,053
Deferred tax liabilities
  Depletion and amortization              (22,431)     (16,064)
  Other                                       (69)          --
                                         ---------------------
                                          (22,500)     (16,064)
                                         ---------------------
Net deferred tax assets (liabilities)    $ (3,200)    $  4,989
                                         =====================
</TABLE>


                                       33

<PAGE>   34
At December 31, 1997 the Company's U.S. net operating tax losses carried
forward amounted to $38,769,000 of which $6,119,000, $2,835,000, $6,139,000,
$18,007,000, $3,773,000 and $1,896,000 expire in the years 2005, 2007, 2009,
2010, 2011 and 2012, respectively. Canadian net operating tax losses carried
forward amounted to $2,605,000 which expire in the year 2003. The Company is of
the opinion that the tax benefit of these tax losses will be realized.

Provisions for deferred income taxes are as follows:

<TABLE>
<CAPTION>
Year ended December 31,            1997       1996       1995
-----------------------------------------------------------------
<S>                               <C>       <C>         <C>
(In thousands)
U.S. Federal and State            $6,067    $ 5,861     $   567
Canada                             2,122      1,239      (2,263)
                                 --------------------------------
                                  $8,189    $ 7,100     $(1,696)
                                 ================================
</TABLE>

     The provision for income taxes differs from the amount of income tax
determined by applying the Canadian statutory rate to pre-tax income before
dividends paid on preferred shares of a subsidiary, as a result of the
following:

<TABLE>
<CAPTION>
Year ended December 31,                          1997        1996          1995
---------------------------------------------------------------------------------
<S>                                            <C>          <C>          <C>
(In thousands)

Tax at statutory Canadian rate of 44.6%        $ 9,213      $ 8,196      $(2,043)
Lower income tax rate on earnings of U.S.
  subsidiaries                                  (1,617)      (1,428)        (150)
Canadian income tax on exchange loss (gain)
  which is eliminated upon consolidation           362          (56)         394
Other                                              238          512          137
                                              -----------------------------------
Tax at effective rate                          $ 8,196      $ 7,224      $(1,662)
                                              ===================================
Effective tax rate                                39.7%        39.3%        36.3%
                                              ===================================
</TABLE>

Cash payments for income taxes for the years 1997, 1996 and 1995 were $141,000,
$26,000 and $44,000, respectively.


                                       34

<PAGE>   35

                       SUPPLEMENTARY FINANCIAL INFORMATION
             CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES

                                DECEMBER 31, 1997

(Unaudited)

RESERVE INFORMATION

Reports prepared by Netherland, Sewell & Associates, Inc. as to the Company's
total U.S. reserves and by the Company as to the U.K. reserves, estimate the
total proved and proved developed producing reserves owned by the Company,
before and after royalty deductions, as follows:

TOTAL PROVED RESERVES BEFORE ROYALTY DEDUCTIONS:

<TABLE>
<CAPTION>
                                                     Natural Gas -- mmcf               Crude Oil & Ngls -- barrels *
                                                 United      North                                 United
                                                 States       Sea         Total                    States
---------------------------------------------------------------------------------------------------------------------
<S>                                             <C>          <C>         <C>        <C>
December 31, 1995                               124,166      25,768      149,934                 9,561,700
  Purchase of producing properties                6,512          --        6,512                    21,200
  Revision of previous estimates                 (2,539)       (127)      (2,666)                  736,900
  Extensions, discoveries and other additions    22,512       1,003       23,515                 1,073,300
  Sale of proved properties                        (404)         --         (404)                  (24,200)
  Production                                    (22,997)     (3,280)     (26,277)                 (850,100)
                                                ----------------------------------------------------------
December 31, 1996                               127,250      23,364      150,614                10,518,800
  PURCHASE OF PRODUCING PROPERTIES                   --          --           --                        --
  REVISION OF PREVIOUS ESTIMATES                  7,029      (1,037)       5,992                 1,317,800
  EXTENSIONS, DISCOVERIES AND OTHER ADDITIONS    21,153          --       21,153                 2,046,400
  SALE OF PROVED PROPERTIES                          --          --           --                        --
  PRODUCTION                                    (24,306)     (4,010)     (28,316)                 (936,300)
                                                ----------------------------------------------------------
DECEMBER 31, 1997                               131,126      18,317      149,443                12,946,700
                                                ==========================================================

</TABLE>

TOTAL PROVED RESERVES AFTER ROYALTY DEDUCTIONS:

<TABLE>
<CAPTION>
                                                     Natural Gas -- mmcf               Crude Oil & Ngls -- barrels *
                                                 United      North                                 United
                                                 States       Sea         Total                    States
---------------------------------------------------------------------------------------------------------------------
<S>                                             <C>          <C>         <C>        <C>

December 31, 1995                               100,923      25,768      126,691                 8,410,900
  Purchase of producing properties                5,171          --        5,171                    17,400
  Revision of previous estimates                 (2,459)       (127)      (2,586)                  648,300
  Extensions, discoveries and other additions    18,720       1,003       19,723                   921,500
  Sale of proved properties                        (303)         --         (303)                  (18,200)
  Production                                    (18,615)     (3,280)     (21,895)                 (727,000)
                                                ----------------------------------------------------------
December 31, 1996                               103,437      23,364      126,801                 9,252,900
  PURCHASE OF PRODUCING PROPERTIES                   --          --           --                        --
  REVISION OF PREVIOUS ESTIMATES                  5,136      (1,037)       4,099                 1,102,800
  EXTENSIONS, DISCOVERIES AND OTHER ADDITIONS    17,628          --       17,628                 1,697,600
  SALE OF PROVED PROPERTIES                          --          --           --                        --
  PRODUCTION                                    (19,421)     (4,010)     (23,431)                 (799,500)
                                                ----------------------------------------------------------
DECEMBER 31, 1997                               106,780      18,317      125,097                11,253,800
                                                ==========================================================
</TABLE>

* 58,900 (1996 - 50,600) barrels of natural gas liquids, before and after
  royalty deductions, associated with the U.K. gas reserves are not included
  in this table.


                                       35

<PAGE>   36

(Unaudited)

PROVED DEVELOPED PRODUCING RESERVES BEFORE ROYALTY DEDUCTIONS:

<TABLE>
<CAPTION>
                              Natural Gas -- mmcf   Crude Oil & Ngls -- barrels
                                 United States             United States
--------------------------------------------------------------------------------
<S>                           <C>                   <C>
December 31, 1995                   51,200                   7,568,700
December 31, 1996                   53,400                   9,175,900
DECEMBER 31, 1997                   55,013                   8,209,000
</TABLE>

PROVED DEVELOPED PRODUCING RESERVES AFTER ROYALTY DEDUCTIONS:

<TABLE>
<CAPTION>
                              Natural Gas -- mmcf   Crude Oil & Ngls -- barrels
                                 United States             United States
--------------------------------------------------------------------------------
<S>                           <C>                   <C>

December 31, 1995                   41,300                   6,747,400
December 31, 1996                   43,000                   8,138,000
DECEMBER 31, 1997                   43,979                   7,241,300
</TABLE>

RESULTS OF OPERATIONS FOR GAS AND OIL PRODUCING ACTIVITIES

<TABLE>
<CAPTION>
Year ended December 31,                                                  1997         1996         1995
-----------------------------------------------------------------------------------------------------------
<S>                                                                    <C>          <C>          <C>
(in thousands)

United States
  Revenue -- net of royalties                                          $ 63,227     $ 56,457     $ 26,122
  Production costs                                                      (14,901)     (13,291)     (11,676)
  Depletion and amortization                                            (33,414)     (28,976)     (18,116)
                                                                       --------     --------     --------
  Results of operations from producing activities before income taxes    14,912       14,190       (3,670)
  Income tax expense                                                     (5,223)      (5,146)       1,128
                                                                       --------     --------     --------
    Results of operations from producing activities after income taxes $  9,689     $  9,044     $ (2,542)
                                                                       ========     ========     ========

United Kingdom
  Revenue -- net of royalties                                          $  6,231     $  4,155     $    552
  Production costs                                                       (1,064)        (904)         (79)
  Depletion and amortization                                             (3,319)      (1,861)        (344)
                                                                       --------     --------     --------
  Results of operations from producing activities before income taxes     1,848        1,390          129
  Income tax expense                                                       (787)        (600)         (56)
                                                                       --------     --------     --------
    Results of operations from producing activities after income taxes $  1,061     $    790     $     73
                                                                       ========     ========     ========

Libya
  Revenue -- net of royalties                                          $    169     $     --     $     --
  Production costs                                                          (38)          --           --
  Depletion and amortization                                               (131)          --           --
                                                                       --------     --------     --------
  Results of operations from producing activities before income taxes        --           --           --
  Income tax expense                                                         --           --           --
                                                                       --------     --------     --------
    Results of operations from producing activities after income taxes $     --     $     --     $     --
                                                                       ========     ========     ========

Total
  Revenue -- net of royalties                                          $ 69,627     $ 60,612     $ 26,674
  Production costs                                                      (16,003)     (14,195)     (11,755)
  Depletion and amortization                                            (36,864)     (30,837)     (18,460)
                                                                       --------     --------     --------
  Results of operations from producing activities before income taxes    16,760       15,580       (3,541)
  Income tax expense                                                     (6,010)      (5,746)       1,072
                                                                       --------     --------     --------
    Results of operations from producing activities after income taxes $ 10,750     $  9,834     $ (2,469)
                                                                       ========     ========     ========
</TABLE>


                                       36

<PAGE>   37

(Unaudited)

CAPITALIZED COSTS RELATING TO GAS AND OIL EXPLORATION AND PRODUCTION ACTIVITIES

<TABLE>
<CAPTION>
December 31,                                          1997        1996        1995
-------------------------------------------------------------------------------------
<S>                                                 <C>         <C>         <C>
(in thousands)

Proved gas and oil properties                       $402,885    $337,538    $286,950
Unproved gas and oil properties                       56,922      52,816      45,731
                                                    --------------------------------
                                                     459,807     390,354     332,681
Accumulated depletion                                224,154     187,403     151,826
                                                    --------------------------------
Net capitalized costs                               $235,653    $202,951    $180,855
                                                    ================================
</TABLE>


COSTS INCURRED IN GAS AND OIL PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT
ACTIVITIES

<TABLE>
<CAPTION>
Year ended December 31,                1997        1996          1995
-------------------------------------------------------------------------
<S>                                  <C>        <C>           <C>
(in thousands)

Property acquisition costs:
  United States                      $ 9,164    $  13,954     $   2,873
  United Kingdom                         137          722           842
  Other Foreign                           --           68            87
                                    -------------------------------------
                                       9,301       14,744         3,802
                                    -------------------------------------
Purchase of producing properties:
  United States                           --        2,077        54,678
                                    -------------------------------------
Sale of producing properties: 
  United States                           --       (1,040)          (21)
                                    -------------------------------------
Exploration costs:
  United States                       35,540       17,453        13,837
  United Kingdom                         115           --             2
  Other Foreign                        1,207          434         2,255
                                    -------------------------------------
                                      36,862       17,887        16,094
                                    -------------------------------------
Development costs:
  United States                       23,260       22,131        15,206
  United Kingdom                          30        1,874        10,743
                                    -------------------------------------
                                      23,290       24,005        25,949
                                    -------------------------------------
                                     $69,453    $  57,673     $ 100,502
                                    =====================================
</TABLE>


                                       37

<PAGE>   38

(Unaudited)

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN
RELATING TO PROVED OIL, NATURAL GAS LIQUIDS AND NATURAL GAS RESERVES

The following standardized measure of discounted future net cash flow was
computed in accordance with Financial Accounting Standards Board Statement #69
using year-end prices and costs, and year-end statutory tax rates. Royalty
deductions were based on laws, regulations and contracts existing at the end of
each period. No values are given to unproved properties or to probable reserves
that may be recovered from proved properties.

The inexactness associated with estimating reserve quantities, future production
streams and future development and production expenditures, together with the
assumptions applied in valuing future production, substantially diminish the
reliability of this data. The values so derived are not considered to be
estimates of fair market value. THE COMPANY THEREFORE CAUTIONS AGAINST
SIMPLISTIC USE OF THIS INFORMATION.

<TABLE>
<CAPTION>
December 31                                                          1997          1996          1995
---------------------------------------------------------------------------------------------------------
<S>                                                               <C>           <C>           <C>
(in thousands)

United States
  Future cash inflows                                             $ 480,669     $ 577,313     $ 363,275
  Future production costs                                          (121,380)     (148,061)     (121,601)
  Future development costs                                          (57,208)      (39,375)      (45,073)
  Future income tax expense                                         (46,742)      (85,464)      (19,846)
                                                                  ---------------------------------------
  Future net cash flows                                             255,339       304,413       176,755
  Ten percent annual discount for estimated timing of cash flows    (70,844)      (89,292)      (50,194)
                                                                  ---------------------------------------
  Standardized measure of discounted future net cash flows          184,495       215,121       126,561
                                                                  ---------------------------------------

United Kingdom
  Future cash inflows                                                32,774        48,392        22,495
  Future production costs                                            (5,734)       (8,045)       (5,562)
  Future development costs                                           (1,450)       (1,603)       (1,338)
  Future income tax expense                                          (6,340)       (6,601)           --
                                                                  ---------------------------------------
  Future net cash flows                                              19,250        32,143        15,595
  Ten percent annual discount for estimated timing of cash flows     (4,172)       (8,241)       (4,662)
                                                                  ---------------------------------------
  Standardized measure of discounted future net cash flows           15,078        23,902        10,933
                                                                  ---------------------------------------

Total
  Future cash inflows                                               513,443       625,705       385,770
  Future production costs                                          (127,114)     (156,106)     (127,163)
  Future development costs                                          (58,658)      (40,978)      (46,411)
  Future income tax expense                                         (53,082)      (92,065)      (19,846)
                                                                  ---------------------------------------
  Future net cash flows                                             274,589       336,556       192,350
  Ten percent annual discount for estimated timing of cash flows    (75,016)      (97,533)      (54,856)
                                                                  ---------------------------------------
  Standardized measure of discounted future net cash flows        $ 199,573     $ 239,023     $ 137,494
                                                                  =======================================
</TABLE>


                                       38

<PAGE>   39

(Unaudited)

The following table sets out principal sources of change in the standardized
measure of discounted future net cash flows during the respective periods.

<TABLE>
<CAPTION>
Year ended December 31,                              1997          1996          1995
----------------------------------------------------------------------------------------
<S>                                               <C>           <C>           <C>
(in thousands)

Sales of oil, ngls and natural gas produced,
  net of production costs                         $ (56,061)    $ (48,233)    $ (17,111)
Net change in prices and production costs           (73,047)      120,858        (5,809)
Extensions and discoveries, less related costs       28,219        50,995        21,866
Purchase of producing properties                         --        10,638        65,975
Sales of producing properties                            --          (436)          (33)
Development costs incurred during the period         10,096        15,026        17,275
Revisions of previous quantity estimates             22,388        (4,462)        4,566
Accretion of discount                                23,902        15,457         6,038
Net change in income taxes                           26,534       (51,064)      (11,656)
Changes in estimated future development costs       (12,551)      (13,950)          495
Other                                                (8,930)        6,700        (4,486)
                                                  ---------     ---------     ---------

Net increase (decrease)                             (39,450)      101,529        77,120
Beginning of year                                   239,023       137,494        60,374
                                                  ---------     ---------     ---------

End of year                                       $ 199,573     $ 239,023     $ 137,494
                                                  =========     =========     =========
</TABLE>


QUARTERLY FINANCIAL INFORMATION

<TABLE>
<CAPTION>
                                                           Per
                                 Gross      Income        Common
Quarter Ended         Revenue    Profit     (loss)        Share
------------------------------------------------------------------
<S>                   <C>        <C>       <C>         <C>
(in thousands except per share amounts)

MARCH 31, 1997        $22,563    $8,444    $ 3,924     $   0.29
JUNE 30, 1997          14,807     1,271       (470)       (0.04)
SEPTEMBER 30, 1997     14,891     1,949         36         0.01
DECEMBER 31, 1997      19,794     5,807      1,728         0.12

March 31, 1996        $13,057    $1,632    $  (157)    $  (0.01)
June 30, 1996          14,941     3,534      1,019         0.08
September 30, 1996     14,610     2,989        693         0.05
December 31, 1996      20,491     7,832      3,287         0.25
</TABLE>


                                       39

<PAGE>   40

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

There have been no disagreements between Chieftain and Chieftain's auditors on
accounting or financial disclosure matters.

                                    PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS

Additional information relating to directors of the Company is incorporated
herein by reference from page 4 of the Company's Information Circular dated
March 20, 1998 for the annual meeting of shareholders on May 14, 1998.

ITEM 11. EXECUTIVE COMPENSATION

"Executive Compensation" on pages 5 to 9 of the Company's Information Circular
dated March 20, 1998 for the annual meeting of shareholders on May 14, 1998 is
incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

"Voting Shares" and "Share Ownership" on pages 2 and 3 of the Company's
Information Circular dated March 20, 1998 for the annual meeting of shareholders
on May 14, 1998 is incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

None.

                                     PART IV

ITEM 14. EXHIBITS AND REPORTS ON FORM 8-K

The following is a listing of the financial statements and financial statement
schedules which are included in this Form 10-K report.

FINANCIAL STATEMENTS

Reference is made to the list of financial statements on page 20 of this report.

EXHIBITS

Reference is made to the Index to Exhibits on page 41 of this report.


                                       40

<PAGE>   41

                                Index to Exhibits

<TABLE>
<CAPTION>
    Exhibit
     Number       Exhibit

<S>               <C>
    *  3 (a)      Articles of Incorporation of the Company.
    *  3 (b)      Articles of Amendment of the Company.
    *  3 (c)      Articles of Amalgamation of the Company.
    *  3 (d)      By-laws number 1 and number 2 of the Company.
   **  4 (a)      Form of Subordinated Guarantee Agreement of the Company.
  ***  4 (b)      Shareholder Rights Plan adopted April 23, 1994.
 **** 10 (a)(i)   Chieftain International, Inc. Retirement Plan as amended May 15, 1997.
 **** 10 (a)(ii)  Chieftain International, Inc. Supplementary Retirement Plan as amended March 20, 1997.
 **** 10 (b)      Chieftain International, Inc. Share Option Plan as amended March 15, 1996.
    * 10 (c)      Chieftain International, Inc. Savings Plan.
    * 10 (d)      Form of indemnification agreement between the Company and each of the officers and directors
                      of the Company.
 **** 21          Information Circular dated March 20, 1998 relating to the Company's annual meeting of shareholders
                      to be held on May 14, 1998.
***** 22          Subsidiaries of the Company.
 **** 24 (a)      Consent of Netherland, Sewell & Associates, Inc.
 **** 24 (b)      Consent of Price Waterhouse.
        27          Financial Data Schedule.

    * Previously filed as an exhibit to the Registration Statement on Form S-1, File No. 33-27254.
   ** Previously filed as an exhibit to the Registration Statement on Form S-1/S-3, File No. 33-51630.
  *** Previously filed as an exhibit to Form 8-K dated March 1, 1994.
 **** Filed herewith.
***** Previously filed as an exhibit to Form 10-K dated March 17, 1994.
</TABLE>


                                       41
<PAGE>   42

                                   SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.

CHIEFTAIN INTERNATIONAL, INC.

<TABLE>
<S>  <C>                                           <C>    <C>
by:  /s/ STANLEY A. MILNER                         by:    /s/ EDWARD L. HAHN
     ------------------------------------                 ----------------------------------------------
     Stanley A. Milner, A.O.E., LL.D.                     Edward L. Hahn
     President and                                        Senior Vice President, Finance and Treasurer
     Chief Executive Officer                              and Chief Financial Officer
</TABLE>

Dated:    March 20, 1998

Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the date indicated.

<TABLE>
<S>                                 <C>                                             <C>
     /s/ D.E. MITCHELL              Director                                        March 20, 1998
----------------------------
     D.E. Mitchell O.C.

      /s/ S.A. MILNER               President, Chief Executive Officer and          March 20, 1998
----------------------------
 S.A. Milner, A.O.E., LL.D.         Director

       /s/ S.C. HURLEY              Director                                        March 20, 1998
----------------------------
        S.C.Hurley

       /s/ H.J. KELLY               Director                                        March 20, 1998
----------------------------
        H.J. Kelly

       /s/ J.E. MAYBIN              Director                                        March 20, 1998
----------------------------
         J.E. Maybin

       /s/ L.G. MUNIN               Director                                        March 20, 1998
----------------------------
         L.G. Munin

      /s/ E.S. ONDRACK              Director                                        March 20, 1998
----------------------------
        E.S. Ondrack

       /s/ S.T. PEELER              Director                                        March 20, 1998
----------------------------
         S.T. Peeler

       /s/ E.L. HAHN                Senior Vice President, Finance and Treasurer    March 20, 1998
----------------------------
         E.L. Hahn                  and Chief Financial Officer

      /s/ R.J. STEFURE              Controller and Chief Accounting Officer         March 20, 1998
----------------------------
       R.J. Stefure
</TABLE>


                                       42