<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, 1998 

Commission File number 1-10216: 

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

<TABLE>
<CAPTION>
            ALBERTA, CANADA                                                                                    NONE 
---------------------------------------------                                                   ------------------------------------
<S>                                                                                             <C>
(State or other jurisdiction of incorporation                                                   (I.R.S. Employer Identification No.)
            or organization) 
</TABLE>



1201 TD TOWER, 10088 - 102  AVENUE,
EDMONTON, ALBERTA, CANADA                                      T5J 2Z1
----------------------------------                          -------------
(Address of Registrant's principal                          (Postal code)
executive offices)  

Registrant's telephone number, including area code:         (780) 425-1950 

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

<TABLE>
<S>                                                          <C>
Title of each class                                          Name of each exchange on which registered


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

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:  NONE 
</TABLE>

Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (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 10, 1999 was US$145,356,000.

The number of shares outstanding of the common stock of Chieftain International,
Inc. on March 10, 1999 was 13,355,891.

                      DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Chieftain International, Inc. Information Circular dated March
11, 1999 for its annual meeting of shareholders to be held on May 13, 1999, are
incorporated by reference into Part III hereof, to the extent indicated herein.
The Exhibits Index can be found on page 40 of this document.


This report contains forward-looking statements that are subject to risk factors
associated with the oil and gas business. The Company believes that the
expectations reflected in these statements are reasonable, but may be affected
by a variety of factors including, but not limited to: price fluctuations,
currency fluctuations, drilling and production results, imprecision of reserve
estimates, loss of market, industry competition, environmental risks, political
risks and capital restrictions.



<PAGE>   2

                          CHIEFTAIN INTERNATIONAL, INC.
                          1998 FORM 10-K ANNUAL REPORT

                                Table of Contents
                                     PART I
<TABLE>
<CAPTION>
                                                                                                          Page
<S>                                                                                                       <C>
    Item 1.  Business ...............................................................................       3
               Segment Information ..................................................................       3
               Principal Properties .................................................................       3
               Acreage ..............................................................................       7
               Gas and Oil Capital Expenditures .....................................................       8
               Drilling Activity ....................................................................       8
               Wells ................................................................................       9
               Reserves .............................................................................       9
               Production Volumes, Prices and Costs .................................................       9
               Marketing ............................................................................      10
               Competition ..........................................................................      10
               Environmental Regulation .............................................................      10
               Regulation and Political Risk ........................................................      10
               Concentration of Gas Production ......................................................      10
               Development of Additional Reserves ...................................................      11
               Exploration and Production Risks .....................................................      11
               Price Uncertainty ....................................................................      11
               Employees ............................................................................      11
               Glossary .............................................................................      12
    Item 2.  Properties .............................................................................      14
    Item 3.  Legal Proceedings ......................................................................      14
    Item 4.  Submission of Matters to a Vote of Security Holders ....................................      14
               Executive Officers of the Registrant .................................................      14

                                                  PART II

    Item 5.  Market for the Registrant's Securities and Related Stockholder Matters .................       15
    Item 6.  Selected Consolidated Financial Data ...................................................       15
    Item 7.  Management's Discussion and Analysis of Financial Condition and Results of Operations ..       17
    Item 8.  Financial Statements and Supplementary Data ............................................       19
    Item 9.  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ...       39

                                                  PART III

    Item 10. Directors and Executive Officers ......................................................       39
    Item 11. Executive Compensation ................................................................       39
    Item 12. Security Ownership of Certain Beneficial Owners and Management ........................       39
    Item 13. Certain Relationships and Related Transactions ........................................       39

                                                  PART IV

    Item 14. Exhibits and Reports on Form 8-K ......................................................       39

Signatures .........................................................................................       41
</TABLE>



                                       2
<PAGE>   3

                                     PART I

ITEM 1. BUSINESS

Chieftain International, Inc., * incorporated under the Business Corporations
Act (Alberta), commenced operations on April 20, 1989 upon conclusion of its
initial public offering. 

Chieftain is engaged in gas and oil exploration and production, primarily in the
United States and also in the UK 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. The Company also participates with various
industry partners who bring additional geoscientific expertise and exploration
prospects to joint venture activity.

In the United States, Chieftain's principal producing properties are located in
the federal waters of the Gulf of Mexico, onshore in Louisiana 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 other areas of the
United States. 

In the Gulf of Mexico, Chieftain holds interests in 152 offshore blocks of which
99 are exploratory and 53 are productive. 

SEGMENT INFORMATION

Reference is made to page 30 hereof for financial information with respect to
the geographic segments of Chieftain for the years ended December 31, 1998, 1997
and 1996.

PRINCIPAL PROPERTIES

Chieftain's principal gas producing properties are located in US federal waters
in the Gulf of Mexico and in the UK sector of the North Sea. Its principal oil
producing properties are located in the Four Corners area of southeast Utah. 

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 1998.
Activity in this area during 1998 was devoted to both exploration for and
development of reserves. Fourteen exploratory wells were drilled, of which six
were successful, and five development wells were drilled, all of which were
successful. 

Additions were made to Chieftain's acreage position in the Gulf of Mexico during
1998. Interests in 11 federal blocks were acquired at competitive lease sales
and interests in two blocks were acquired through joint venture operations.
Holdings in the offshore Gulf of Mexico amounted to 727,113 gross (283,549 net)
acres at year-end compared to 701,764 gross (260,232 net) acres at December 31,
1997. Ongoing acquisition of three-dimensional seismic data supports the
Company's exploration efforts. Continued development activity is contributing to
production growth. 


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



* 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

WESTERN GULF (OFFSHORE TEXAS)

MUSTANG ISLAND:

<TABLE>
Blocks       Gross Acres       Net Acres       Average Interest       Average Production
------       -----------       ---------       ----------------       ------------------
<S>          <C>               <C>             <C>                    <C>
 7            32,619           15,950             46.8%                  9.1 mmcfd
</TABLE>

Successful recompletion of a well on Block 784 (Chieftain 50%) increased average
daily production from 4.6 mmcfd in 1997. An unsuccessful exploratory well (100%
Chieftain) was drilled on Block 758 which was allowed to expire. An unsuccessful
exploratory well was drilled on South Addition Block A-51 (Chieftain 25%).


MATAGORDA ISLAND: 

<TABLE>
<CAPTION>
Blocks       Gross Acres       Net Acres       Average Interest       Average Production
------       -----------       ---------       ----------------       ------------------
<S>          <C>               <C>             <C>                    <C>
  9            47,610           16,735             34.3%                 14.1 mmcfd
</TABLE>

On Block 634 (Chieftain 24%) three dimensional seismic data was used to identify
a deep prospect beneath the producing reservoir. A 13,000-foot exploratory gas
well encountered five new productive zones. The well was completed during the
second quarter in one zone and was producing 3.0 mmcfd net to Chieftain at
year-end.

HIGH ISLAND:

<TABLE>
<CAPTION>
Blocks       Gross Acres       Net Acres       Average Interest       Average Production
------       -----------       ---------       ----------------       ------------------
<S>           <C>              <C>             <C>                    <C>
  33           145,572          66,652             41.5%              7.6 mmcfd and 94 bd
</TABLE>

A platform was installed on Block 207 (Chieftain 50%) and production commenced
from a discovery well drilled in 1996. Further drilling is planned for this
block in 1999.

In the High Island South Addition area, Chieftain has interests in eight blocks
(50% in seven; 100% in one) with gas exploration potential. Exploratory drilling
is scheduled to test prospects at depths of 6,000 to 11,000 feet on Blocks
A-510, A-566 and A-530. Access to pipeline facilities is now available in the
area.

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           18,160             31.1%              3.9 mmcfd and 507 bd
</TABLE>

A discovery well was drilled on Block 34 (Chieftain 40%) early in 1998.
A platform was installed and production commenced in the fourth quarter. Further
drilling is planned in 1999. In the newly-developed Block 349/350 field
(Chieftain 25%) an additional oil and gas development well was drilled, also
early in the year. Production was shut-in for repairs to a third-party pipeline,
interrupting oil production until March. Production was further restricted by
mechanical well problems through the summer. After two wells were successfully
recompleted, production was restored during the fourth quarter. An unsuccessful
exploratory well (Chieftain 33%) was drilled on Block 329.


VERMILION: 

<TABLE>
<CAPTION>
Blocks       Gross Acres       Net Acres       Average Interest       Average Production
------       -----------       ---------       ----------------       ------------------
<S>          <C>              <C>              <C>                    <C>      
  6            20,806           13,447             56.7%                  1.6 mmcfd
</TABLE>

On Block 23 (Chieftain 25%) production increased with the drilling of a
successful development well. Further development drilling is being considered
for 1999. Exploratory wells are planned for Blocks 16 (Chieftain 40%) and 267
(Chieftain 60%). An unsuccessful exploratory well (Chieftain 15%) was drilled on
Block 368.


SOUTH MARSH ISLAND:

<TABLE>
<CAPTION>
Blocks       Gross Acres       Net Acres       Average Interest       Average Production
------       -----------       ---------       ----------------       ------------------
<S>          <C>               <C>             <C>                    <C>
  4            17,852            9,852              60%                       -
</TABLE>


Two successful exploratory oil and gas wells were drilled on Block 39 (Chieftain
50%) during 1998 to followup and further evaluate two 1997 oil and gas
discoveries. Production facilities with initial capacity, net to Chieftain, of
2,500 bd of oil and 20 mmcfd of gas, were under construction at year-end and
production is expected to commence in late March, 1999. Several follow-up wells
are planned for 1999.



                                       4
<PAGE>   5

EUGENE ISLAND:

<TABLE>
<CAPTION>
Blocks       Gross Acres       Net Acres       Average Interest       Average Production
------       -----------       ---------       ----------------       ------------------
<S>          <C>               <C>             <C>                    <C> 
  6            26,250            8,105             36.7%              2.7 mmcfd and 30 bd
</TABLE>


On Block 83 (Chieftain 40%) production commenced from a 1997 gas discovery in
early 1998. On Block 189 (Chieftain 75%), where two oil and gas discoveries were
drilled on separate fault blocks in 1997, development work is planned,
contingent upon satisfactory prices. The plan contemplates the drilling of at
least one development well and use of processing facilities on an adjacent
block. An exploratory well drilled in December 1998 on another fault block
encountered non-commercial gas reserves.


SOUTH TIMBALIER:

<TABLE>
<CAPTION>
Blocks       Gross Acres       Net Acres       Average Interest       Average Production
------       -----------       ---------       ----------------       ------------------
<S>          <C>               <C>             <C>                    <C>
  5            22,186            9,843              40%                       -
</TABLE>

On Block 196, Chieftain will participate in the drilling of a 12,000-foot
gas-prospective exploratory well to earn a 50% interest.


EASTERN GULF

MISSISSIPPI CANYON:

<TABLE>
<CAPTION>
Blocks       Gross Acres       Net Acres       Average Interest       Average Production
------       -----------       ---------       ----------------       ------------------
<S>          <C>               <C>             <C>                    <C>      
  4            23,040            5,520             24.1%                  0.1 mmcfd
</TABLE>

An 8,000-foot well drilled in 2,500 feet of water on Block 29 (Chieftain 33%)
resulted in an oil discovery. Results are being evaluated but further drilling
is unlikely until oil prices recover.


MAIN PASS EAST ADDITION: 

<TABLE>
<CAPTION>
Blocks       Gross Acres       Net Acres       Average Interest         Average Production
------       -----------       ---------       ----------------         ------------------
<S>          <C>               <C>             <C>                    <C>
  11           46,984            7,864             15.3%              17.5 mmcfd and 260 bd
</TABLE>


Field development and evaluation activity continued during 1998 on Blocks
222/223 and 225 where Chieftain has interests of from 7% to 10% in two natural
gas fields which were among the largest industry discoveries on the Shelf in
1995. Additional pipeline capacity for production from the area became available
in the second quarter of 1998. Production commenced from Block 217 (Chieftain
20%) in March and subsequently Chieftain participated with interests ranging
from 8% to 20% in three successful gas development wells on Blocks 223 and 250.
Production facilities are being installed on Block 250 (Chieftain 20%) to
connect an additional discovery and further drilling is planned for this block.
Production is expected to commence in the second quarter of 1999. During 1999,
production facilities are also expected to be installed on the west half of
Block 225 (Chieftain 10%) to connect two gas wells.


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%                  7.4 mmcfd
</TABLE>

An unsuccessful exploratory well was drilled to test a deep Norphlet sandstone
gas prospect on Block 914. The farmee did not earn and Chieftain retains
interests of 25% in Block 914 and 38% in the adjoining Block 913.


VERMILION PARISH, LOUISIANA

NORTHEAST WRIGHT: 

<TABLE>
<CAPTION>
Gross Acres       Net Acres       Average Interest       Average Production
-----------       ---------       ----------------       ------------------
<S>               <C>             <C>                    <C>
 3,037            1,518             50.0%                  0.2 mmcfd
</TABLE>

During 1998, Chieftain acquired an interest in the Northeast Wright Field area,
which included the Simon #2 producing well and the D.W. Guidry #1 exploratory
well. Subsequent to the Chieftain acquisition, the operator reported that the
Guidry well had discovered 150 feet of net natural gas pay and stated: "The well
encountered hydrocarbons in the prolific Marg. Tex formation within a 600-foot
interval below 17,000 feet". The discovery confirms the presence of a large
structure underlying the Northeast Wright Field. The Guidry well was drilled as
a 3,000-foot offset to the Simon #2 well which commenced production in May 1996.
Chieftain's interest in the Guidry well, which commenced production in late
December, is subject to a penalty on a portion of the cost of the well. The
significance of the find to Chieftain will be determined by further drilling. An
offset exploration well is scheduled to commence drilling in the second quarter
of 1999.



                                       5
<PAGE>   6

FOUR CORNERS (PARADOX BASIN) AREA, UTAH

Aneth Unit:

<TABLE>
<CAPTION>
Gross Acres       Net Acres       Average Interest         Average Production
-----------       ---------       ----------------         ------------------
<S>               <C>             <C>                   <C>
 18,070            3,066             13.4%              0.25 mmcfd and 646 bd
</TABLE>

Ratherford Unit:

<TABLE>
<CAPTION>

Gross Acres       Net Acres       Average Interest         Average Production
-----------       ---------       ----------------         ------------------
<S>               <C>             <C>                    <C>
  12,910            2,560             21.4%              0.5 mmcfd and 1,546 bd
</TABLE>

Chieftain has interests in two unitized light oil fields where horizontal
drilling has improved the effectiveness of the waterflood enhanced recovery
program, resulting in increased recoverable reserves and production. During the
year, 30 multi-lateral horizontal development wells were drilled in the Units.
A tertiary carbon dioxide recovery pilot project is underway in the Aneth Unit,
and a field-wide tertiary recovery project is planned for the Ratherford Unit.
Activity at Aneth and Ratherford may be limited by low oil prices during 1999.


NORTH SEA - UNITED KINGDOM SECTOR

<TABLE>
<CAPTION>
Gross Acres      Net Acres       Average Interest       Average Production
-----------      ---------       ----------------       ------------------
<S>              <C>             <C>                   <C>
  60,273          9,644             17.7%              8.5 mmcfd and 25 bd
</TABLE>


Chieftain adjusts its gas sales from this area month by month in response to
prices. Accordingly, volumes averaged 15.3 mmcfd in the first quarter and 10.3
mmcfd in the fourth quarter, when prices were relatively high, and were reduced
to 1.8 mmcfd during the third quarter when prices were at a seasonal low. In
addition, production was shut-in for several weeks during July for maintenance
work. Chieftain's production, which is royalty-free, is sold under 30-day
contracts and in 1998 obtained an average price of $1.40 per mcf, net of
transportation costs.

SIRTE BASIN, LIBYA

<TABLE>
<CAPTION>
Gross Acres       Net Acres       Average Interest       Average Production
-----------       ---------       ----------------       ------------------
<S>               <C>             <C>                    <C>   
 3,888,550         486,068             12.5%                   284 bd
</TABLE>

A long-term production test commenced in December 1997 on Block 5 of the Libya
concession NC-171. The first tanker load of this light gravity oil was shipped
to European refineries in July. The objective of the production test is to
determine if well performance supports full-scale commercial development
including development drilling and production facility upgrades. Testing will
continue from two wells into 1999. Reserves have not been booked pending
determination of commerciality. At that time, after recovery of certain costs,
Chieftain's interest in the production will be reduced. A well drilled in early
1999 on Block 5 found oil insufficient to warrant completion. One exploratory
well remains to be drilled under the terms of the concession.



                                       6
<PAGE>   7

ACREAGE

The following table summarizes the developed and undeveloped acreage held by
Chieftain as at December 31, 1998. 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 ..................      21,672         6,620       329,880       111,342
      Texas ......................      12,835         3,664       355,394       160,073
      Texas State ................         300            22         7,032         1,828
                                        ------        ------     ---------       -------
   Total Offshore Gulf of Mexico..      34,807        10,306       692,306       273,243
                                        ======        ======     =========       =======

   Onshore
      Louisiana ..................       1,936           754         1,674           836
      Montana ....................          --            --         3,240         3,240
      North Dakota ...............         997           227         1,280           188
      Pennsylvania ...............         324            36            --            --
      Texas ......................         320            80            --            --
      Utah .......................      29,860         4,895         1,120           731
                                        ------        ------     ---------       -------
   Total Onshore .................      33,437         5,992         7,314         4,995
                                        ======        ======     =========       =======

Total United States ..............      68,244        16,298       699,620       278,238
                                        ======        ======     =========       =======

United Kingdom
   North Sea .....................       7,584         1,348        52,689         8,296
                                        ======        ======     =========       =======

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

Total, all areas .................      75,828        17,646     4,640,859       772,602
                                        ======        ======     =========       =======
</TABLE>


Chieftain's developed and undeveloped acreage in all areas covered 4,716,687
gross (790,248 net) acres at December 31, 1998.

The undeveloped acreage has not been independently evaluated. The cost to
Chieftain thereof is approximately $48 million.



                                       7
<PAGE>   8

GAS AND OIL CAPITAL EXPENDITURES

The following table summarizes Chieftain's net capital expenditures for the
years ended December 31, 1998 and 1997.

<TABLE>
<CAPTION>
Year ended December 31,                     1998             1997
---------------------------------          -------          -------
                                               (in thousands)
<S>                                        <C>              <C>    
Property acquisition costs:
   United States ................          $ 7,903          $ 9,164
   United Kingdom ...............              115              137
                                           -------          -------
                                             8,018            9,301
                                           -------          -------
Purchase of producing properties:
   United States ................              883               --
                                           -------          -------
Exploration costs:
   United States ................           43,317           35,540
   United Kingdom ...............               72              115
   Other foreign ................              606            1,207
                                           -------          -------
                                            43,995           36,862
                                           -------          -------
Development costs:
   United States ................           39,606           23,260
   United Kingdom ...............               71               30
                                           -------          -------
                                            39,677           23,290
                                           -------          -------
                                           $92,573          $69,453
                                           =======          =======
</TABLE>

DRILLING ACTIVITY

The following table summarizes the results of Chieftain's drilling activities
during the years ended December 31, 1998 and 1997.

Exploratory Wells - Year ended December 31, 
-------------------------------------------
<TABLE>
<CAPTION>
                                      1998                      1997
                               Gross         Net         Gross         Net
                               -----         ---         -----         ---
<S>                            <C>           <C>         <C>           <C> 
Gas .....................         6          1.91           7          2.82
Oil .....................         1          0.33          --            --
Oil/Gas .................        --            --           1          0.50
Evaluating ..............        --            --          --            --
Drilling at end of year..        --            --           3          0.94
Abandoned ...............         8          3.45           9          2.99
                               ----          ----          --          ----
                                 15          5.69          20          7.25
                               ====          ====          ==          ====
</TABLE>

Development Wells - Year ended December 31,
-------------------------------------------
<TABLE>
<CAPTION>
                                      1998                      1997
                               Gross         Net         Gross         Net
                               -----         ---         -----         ---
<S>                            <C>           <C>         <C>           <C> 
Gas .....................         4          0.32           9          1.77
Oil .....................        30          6.01          34          6.15
Oil/Gas .................         1          0.25          --            --
Evaluating ..............        --            --          --            --
Drilling at end of year..        --            --           4          0.81
Abandoned ...............        --            --           1          0.50
                               ----          ----          --          ----
                                 35          6.58          48          9.23
                               ====          ====          ==          ====
</TABLE>



                                       8
<PAGE>   9

WELLS

Chieftain's productive gas and oil wells as at December 31, 1998 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 ................       --             --          269          44.69
Louisiana ...........        3           1.13           --             --
US Gulf of Mexico....       89          17.97           16           4.70
United Kingdom ......        3           0.41           --             --
                           ---          -----          ---          -----
                           100          20.44          287          49.86
                           ===          =====          ===          =====
</TABLE>

In addition, Chieftain has interests in three (0.37 net) oil wells in Libya two
of which 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 US reserves and by the Company as to the
UK 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, 1998 and 1997 is
listed below. Also listed are average sales prices and average production costs
during such periods.

<TABLE>
<CAPTION>
Year ended December 31,                   1998                1997
-----------------------                   ----                ----
<S>                                    <C>                 <C>   
Total Net Production:
   Gas (mmcf) ...............              24,504              23,431
   Oil and liquids (mb) .....               1,100                 825
   Gas equivalent (mmcf) ....              31,102              28,383

Average Daily Net Production:
   Gas (mmcf) ...............                67.1                64.2
   Oil and liquids (b) (*) ..               3,012               2,261
   Gas equivalent (mmcf) ....                85.2                77.8

Average Sales Price:
   Gas (per mcf) ............          $     1.99          $     2.33
   Oil and liquids (per b) ..          $    11.74          $    18.94

Average Production Cost:
   Gas (per mcf) ............          $     0.30          $     0.27
   Oil and liquids (per b) ..          $     5.78          $     5.81
</TABLE>


        (*) Oil comprised approximately 82% of the oil and liquids production
over the periods shown.



                                       9
<PAGE>   10

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 production in the US spot market. Gas prices in the US and in
the UK 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 US gas producers, at prices based on
spot market prices. Highland Energy Company has also represented Chieftain in
relation to the marketing of Chieftain's UK 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.

US 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 UK, 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, 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 US
Gulf of Mexico and could be adversely affected by natural disasters or market
conditions affecting this area.



                                       10
<PAGE>   11

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 and 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 to 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 have 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, 1998, Chieftain had 40 full-time equivalent employees. In
addition, Chieftain engages the services of consultants as required.



                                       11
<PAGE>   12

GLOSSARY

The following are defined terms used herein:

BARREL (b) means 34.972 Imperial gallons or 42 US 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.

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.



                                       12
<PAGE>   13

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.



                                       13
<PAGE>   14

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 proceding.

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 1998. 

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
13, 1999.

<TABLE>
<CAPTION>
NAME              AGE       POSITION/OFFICE
----              ---       ---------------
<S>               <C>       <C>
S.A.Milner        70        Director, President and Chief Executive Officer
S.C.Hurley        49        Director, Senior Vice President and Chief Operating Officer
E.L.Hahn          61        Senior Vice President, Finance and Treasurer
E.S.Ondrack       58        Director, Senior Vice President and Secretary
S.J.Milner        41        Vice President, Drilling and Production
R.J.Stefure       51        Vice President and 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 US 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 who are first cousins and between
S.A. Milner and S.J. Milner who are father and son.



                                       14
<PAGE>   15

                                    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,
1996 are shown below.

<TABLE>
<CAPTION>
                            Price History of Chieftain International, Inc.Common Shares
                              American Stock Exchange       The Toronto Stock Exchange
                                  (US dollars)                    (Cdn. dollars)
                                High           Low             High           Low
                                ----           ---             ----           ---

<S>                          <C>           <C>              <C>           <C>      
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
   First quarter                 24.75         17.94            30.35         25.60
   Second quarter                24.75         20.25            35.35         30.10
   Third quarter                 23.75         13.94            34.45         21.60
   Fourth quarter                20.25         14.38            30.70         22.75

1999
   January                       15.50         11.88            23.00         17.00
   February                      12.88          9.56            19.50         14.50
   March 1 to March 10           10.87          9.87            17.10         15.10
</TABLE>


The Common Shares were held by 107 shareholders of record on December 31, 1998.
The Company estimates that investment dealers and other nominees hold Common
Shares for approximately 2,571 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, 1998 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.



                                       15
<PAGE>   16

               SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA

                  CHIEFTAIN INTERNATIONAL,INC. AND SUBSIDIARIES

<TABLE>
<CAPTION>
Year ended December 31,                                         1998           1997          1996          1995           1994
-----------------------                                     -----------    -----------   -----------   -----------    ----------- 
                                                            (in thousands except shares, per share amounts and operating data)
<S>                                                     <C>             <C>            <C>            <C>             <C>        
INCOME STATEMENT DATA:
Revenue ...............................................     $    64,391    $    72,055   $    63,099   $    31,071    $    34,876
Production costs ......................................          16,355         13,325        12,220         9,563          8,839
General and administrative expenses ...................           4,796          4,308         3,972         3,346          3,402
Interest ..............................................             437             --            --            --             --
Depletion and amortization(1) .........................          42,081         36,951        30,920        18,779         21,527
Additional depletion(2) ...............................           6,244             --            --            --         15,434
Income (loss) from operations, before dividends
   on preferred shares of a subsidiary ................          (4,113)        10,160         9,784          (775)        (9,528)
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) ......          (9,055)         5,218         4,842        (5,717)       (14,470)
Net income (loss) per common share(1)..................           (0.67)          0.38          0.37         (0.54)         (1.32)
Weighted average number of common shares outstanding...      13,480,067     13,620,728    13,065,414    10,633,142     10,986,116

OTHER DATA:
Cash flow from operations .............................     $    37,847    $    49,473   $    41,841   $    13,186    $    17,647
Net gas and oil capital expenditures ..................     $    92,573    $    69,453   $    57,673   $   100,502    $    28,059

BALANCE SHEET DATA (at end of period):
Working capital .......................................     $     2,383    $    22,676   $    42,854   $    11,216    $   103,225
Total assets(1) .......................................     $   318,584    $   285,125   $   267,442   $   204,555    $   211,032
Long-term debt ........................................     $    40,000    $        --   $        --   $        --    $        --
Shareholders' equity(1) ...............................     $   234,946    $   249,466   $   244,122   $   190,534    $   200,754

OPERATING DATA:
Average Daily Net Production:
   Gas (mmcf) .........................................            67.1           64.2          59.8          29.5           28.4
   Oil and liquids (b) ................................           3,012          2,261         2,005         1,643          1,631
   Gas equivalent (mmcf) ..............................            85.2           77.8          71.8          39.3           38.2
Average Sales Price:
   Gas (per mcf) ......................................     $      1.99    $      2.33   $      2.09   $      1.54    $      1.97
   Oil and liquids (per b) ............................           11.74          18.94         20.99         16.94          15.86
Average Production Cost:
   Gas (per mcf) ......................................     $      0.30    $      0.27   $      0.25   $      0.35    $      0.34
   Oil and liquids (per b) ............................            5.78           5.81          6.57          7.31           6.79
</TABLE>

Notes:

        (1)     Reference is made to Note 11 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 UK and
                Libyan gas and oil properties in 1998 and US and Peruvian gas
                and oil properties in 1994 in accordance with full cost
                accounting rules under Canadian GAAP.



                                       16
<PAGE>   17

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

To be read in conjunction with the 1998 audited consolidated financial
statements.

(Comparisons are with 1997 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, Utah and
Louisiana and also in the British sector of the North Sea and in Libya.
Chieftain continues to explore in these areas. 

The Company dedicates the majority of its attention and resources to the US Gulf
of Mexico area where it holds interests in 152 offshore lease blocks. Highly
skilled technical staff and leading-edge technology are employed in the
Company's Dallas and New Orleans exploration offices to identify and delineate
gas and oil prospects. 

The Company's reporting currency is the US dollar. 

ANALYSIS OF OPERATING RESULTS

Average daily production in 1998 increased to 103 mmcfe from 93 mmcfe and 86
mmcfe in 1997 and 1996, respectively. Natural gas production increased to 30 bcf
in 1998 from 28 bcf in 1997 and 26 bcf in 1996. Oil production increased to
1,271,000 b in 1998 from 962,000 b in 1997 and 857,000 b in 1996. In 1998,
positive growth in production volumes was more than offset by decreases in
natural gas and oil prices with the result that production revenues decreased
11% to $74.8 million. This compares to an increase in 1997 production revenues
of 16% to $84.2 million, which resulted from positive growth in production
volumes and a significant increase in average natural gas prices during 1997.
Natural gas prices in 1998 averaged $1.99 per mcf compared to $2.33 in 1997 and
$2.09 in 1996. Oil prices in 1998 averaged $11.74 per b compared to $18.94 in
1997 and $20.99 in 1996.

Higher rates of production are anticipated during 1999 as newly developed
fields, particularly South Marsh Island 39, are brought on stream; a full year's
production is yielded by fields and wells that first contributed during 1998,
such as East Cameron 34, Eugene Island 83, Main Pass 217, High Island 207 B-1
and Northeast Wright; and a full year's production is contributed by areas that
were subject to pipeline constraints during 1998, such as East Cameron 349, Main
Pass 222/223, and South Pass 37.

A $0.10 per mcf change in the average natural gas price received would have
resulted in a change in revenue, cash flow and pre-tax income of $2.5 million
(1997 - $2.3 million; 1996 - $2.3 million). A $1.00 per barrel change in the
average oil price would have resulted in a change in revenue of $1.1 million and
a change in cash flow and pre-tax income of a slightly lesser amount (1997 -
$0.8 million; 1996 - $0.7 million).

In Libya, a long-term production test which commenced in December 1997 will
require a longer test period to produce a reservoir model which will assess
reserve quantities and economics of additional drilling. An impairment provision
of $5.1 million was recorded in respect of one of the Libyan concessions upon
which no further exploration has currently been planned. Two additional wells
will be drilled in 1999 to fulfil the Company's commitment in this area.

PRODUCTION AND PRICING 

During 1998, Chieftain's production averaged 103.2 mmcfe per day, an increase of
11% from 1997. The daily production rate at the end of 1998 was 120.0 mmcfe, an
increase of 25% over the 1997 year-end production rate. The year's production
mix, on an energy equivalent basis, was 80% natural gas and 20% oil and ngls. On
a geographic basis, 90% of energy equivalent production came from United States
properties which are expected to account for 93% of 1999 production.

Ninety per cent of 1998 natural gas production came from Chieftain's interests
in 105 wells in the Gulf of Mexico. Gas production was up by 6%, with increases
from the Main Pass, Mustang Island, Eugene Island, East Cameron, High Island and
Vermilion areas. Recently developed facilities at High Island 207, several Main
Pass blocks, Matagorda 634 and South Marsh Island 39, and production from the
onshore Northeast Wright Field in Louisiana, are expected to increase gas
production in 1999. In the North Sea, three wells, one of which has two
laterals, produce natural gas and ngls.

Production of oil and ngls increased by 32% with the largest increases
contributed by holdings in the East Cameron and Main Pass areas in the Gulf of
Mexico, and the Aneth and Ratherford Units in southeast Utah. During 1998, 63%
of the Company's oil production was from interests in 269 wells in the Aneth and
Ratherford Units and 28% was from the Gulf of Mexico. Oil production growth
during 1999 is expected from South Marsh Island 39, East Cameron 349 and the
Utah Units.



                                       17
<PAGE>   18

At year-end, Chieftain was producing, before royalties, 95.5 mmcfd of gas,
comprising 85.2 mmcfd in the US and 10.3 mmcfd in the North Sea. Year-end oil
production, before royalties, was 4,030 bd, 2,170 bd from the Aneth and
Ratherford Units in Utah and 1,550 bd from the Gulf of Mexico. An additional 220
bd was contributed by interests in two wells in Libya's Sirte Basin where a
long-term production test is continuing.

The combination of serious economic problems in Asia, the warmest North American
winter in the last century and aggressive international competition for market
share caused crude oil prices to fall sharply during 1998, bringing the average
price received by Chieftain for oil and ngls down by 38% to $11.74.

The extremely mild North American winter of 1997-98 had a significant downward
effect on natural gas prices in the Gulf of Mexico. Prices during the fourth
quarter were down by 33% from the comparative quarter of 1997. The average price
received for all of Chieftain's 1998 US gas production declined by 17% to an
average of $2.06 per mcf. Gas production contributed 78% of revenue.

Chieftain sells most of its gas under short term contractual arrangements and
does not engage in speculative forward selling of volumes that cannot be
physically delivered.

Interest and other revenue in 1998 includes a non-recurring court award of $1.6
million pursuant to a successful claim for recovery of excess transportation
charges incurred from 1990 through 1997.

In 1998, production expenses increased 23%, primarily reflecting a succession of
weather induced evacuations of manned facilities in the Gulf of Mexico during
the third quarter, the commencement of production at East Cameron 349 and
significant pipeline repair costs in the South Pass area. Production expenses
increased to $0.43 per gas equivalent unit, up 11% from the 1997 and 1996 rate
of $0.39 per gas equivalent unit. Higher lifting costs are associated with oil
production which comprised 20% of the Company's gas equivalent production in
1998 as compared to 17% in 1997 and 16% in 1996.

For 1998, the 11% increase in general and administrative expense reflects
increased performance based compensation payments made during the first quarter.
General and administrative expenses were $0.13 per gas equivalent unit in 1998,
1997 and 1996.

Depletion and amortization expense increased 14% compared to 1997, the result of
an 11% increase in units of production and a 4% increase in average depletion
rate to $1.12 per gas equivalent unit.

Capital Resources and Liquidity

The table on this page summarizes cash provided from or (used in) operating,
financing and investing activities for each of the past three years.

Cash generated from operating activities decreased 30%, primarily as a result of
lower revenues in 1998.

Financing activities in 1998 provided $ 34.5 million of cash, the net result of:
the drawdown of $ 40 million of the Company's revolving credit facility, the
purchase for cancellation of 294,700 common shares at the cost of $5.9 million
under a normal course issuer bid and the exercise of employee stock options for
$0.4 million. In 1997, financing activities provided $0.1 million of cash, the
net result of the exercise of employee stock options for $1.0 million and the
purchase for cancellation of 36,300 common shares at the cost of $0.9 million.

Source and Use of Cash (US$ in thousands)

<TABLE>
<CAPTION>
Year ended December 31,               1998          1997          1996
                                    --------      --------      --------
<S>                                 <C>           <C>           <C>
Cash provided from (used in):
  Operating activities              $ 35,167      $ 50,489      $ 36,967
  Financing activities                34,535           126        47,657
  Investing activities               (86,014)      (66,139)      (52,750)
                                    --------      --------      --------
Increase (decrease) in cash         $(16,312)     $(15,524)     $ 31,874
                                    ========      ========      ======== 
</TABLE>



Cash used in investing activities increased 30% to $86.0 million in 1998. The
Company participated in 50 wells in 1998, compared to 68 wells in 1997. All 1998
and 1997 drilling was in the US.

The December 31, 1998 cash balance of $10.6 million was down $16.3 million from
a year earlier. $40 million of the Company's $100 million revolving credit
facility was utilized at December 31, 1998. The weighted average interest rate
at December 31, 1998 was 5.65%.

OUTLOOK 

The Company's 1999 production target range is 115 to 125 mmcfe per day as
compared to average production of 103 mmcfe per day in 1998. Low oil and gas
prices, if prolonged, may more than offset any increase in cash flow
contribution from increased production volumes.



                                       18
<PAGE>   19

The abnormally temperate 1998-1999 heating season associated with El Nino has
resulted in robust US gas storage levels in the primary markets for the
Company's US gas production. It is difficult to predict the extent to which
industry declines in production will be offset by new production in the near
term. The Company expects that the resulting uncertainty about US gas supply,
coupled with abnormally low US consumption, will result in continued US gas
price volatility.

In the North Sea, the direction of flow in the Interconnector pipeline has been
reversed as a consequence of spot prices on the continent falling below United
Kingdom prices, a result of surplus natural gas from the former Soviet Union
reaching the continental market. The Company expects continued low prices for
North Sea production in the near term.

The Board of Directors authorized a $75 million capital expenditure program for
1999. 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. The Company continuously
monitors capital spending with a view to oil and gas prices so as to adjust
investment levels in relation to cash flow projections.

Many of the Company's competitors and partners are reviewing and reducing their
capital expenditure programs in view of the low oil and gas prices expected in
the near term. The uncertainty underlying these spending reductions is expected
to result in delays in the timing of projects, cancellation of projects, reduced
costs of projects and the possibility of purchasing reserves at values
reflecting low current prices.

YEAR 2000 DISCLOSURE

The Company has completed the assessment of its internal Year 2000 issues, has
made changes and employed testing procedures as deemed necessary and at this
time is confident that no issues relating to its internal systems remain which
could have a material effect on its financial condition or results of
operations. The Company's assessment of the readiness of third parties is in
process and should be completed by the end of the second quarter of 1999. Costs
incurred to date and expected to be incurred in the future are not material to
the Company. 


The Company has interests in a substantial number of offshore oil and gas
production facilities which are operated by others and is required to rely on
assessments by such third parties as to Year 2000 readiness of such facilities.
Production volumes are transported through pipelines and processed through
facilities which are also operated by third parties. There is extensive use of
computers to control and operate such pipelines and facilities in the oil and
gas industry and it is reasonably likely that one or more of such facilities
will experience a computer related event which could result in shut down of
production, transportation or processing facilities for such time as is required
to effect alternative controls. The Company can not reasonably quantify the
estimated lost revenue, if any, which would result from such an interruption. To
mitigate the effect of any interruptions, the Company intends to continue its
review of contingency plans prepared by its various operating partners.

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 US dollars.

        Management's Report

        Auditors' Report

        Consolidated Balance Sheet as at December 31, 1998 and 1997

        Consolidated Statement of Income and Deficit for the years ended
        December 31, 1998, 1997 and 1996

        Consolidated Statement of Changes in Financial Position for the years
        ended December 31, 1998, 1997 and 1996

        Notes to Consolidated Financial Statements

        Supplementary Financial Information (Unaudited)



                                       19
<PAGE>   20

MANAGEMENT'S REPORT

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.A. Milner
President and Chief Executive Officer 


/s/ E.L. Hahn 
---------------------------------------
E.L. Hahn 
Senior Vice President, 
Finance and Treasurer 

February 4, 1999

AUDITOR'S REPORT

We have audited the consolidated balance sheets of Chieftain International, Inc.
as at December 31, 1998 and 1997 and the consolidated statements of income
(loss) and deficit and changes in financial position for each of the years in
the three-year period ended December 31, 1998. 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, 1998 and 1997 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, 1998 in accordance with generally accepted accounting principles in Canada.




/s/ PricewaterhouseCoopers LLP
---------------------------------------
Chartered Accountants
Edmonton, Alberta

February 4, 1999



                                       20
<PAGE>   21

CONSOLIDATED BALANCE SHEET
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES


<TABLE>
<CAPTION>
(Full Cost Method of Accounting) as at December 31,                                1998                1997
                                                                                 ---------           ---------
                                                                                       (US$ in thousands)
<S>                                                                              <C>                 <C>      
Assets
Current assets:
   Cash and short-term deposits                                                  $  10,613           $  26,925
   Accounts receivable                                                              14,030              10,862
   Other                                                                               282                 606
                                                                                 ---------           ---------
                                                                                    24,925              38,393
                                                                                 ---------           ---------
Capital assets, at cost:
   Natural resource properties including exploration and
      development thereon (Note 1(e))                                              552,380             459,807
   Other capital assets                                                              2,119               2,047
                                                                                 ---------           ---------
                                                                                   554,499             461,854
   Less: Accumulated depletion and amortization                                    266,022             218,564
                                                                                 ---------           ---------
                                                                                   288,477             243,290
                                                                                 ---------           ---------

Deferred income taxes                                                                5,182               3,442
                                                                                 ---------           ---------

                                                                                 $ 318,584           $ 285,125
                                                                                 =========           =========
Liabilities and Shareholders' Equity
Current liabilities:
   Accounts payable and accrued                                                  $  22,533           $  15,717

Long-term debt (Note 2)                                                             40,000                  --

Abandonment cost accrual                                                             7,421               6,575

Deferred income taxes                                                               13,684              13,367

Shareholders' equity:
   Preferred shares of a subsidiary (Note 3)                                        63,403              63,403
   Share capital (Note 4) -
      Authorized - an unlimited number of -
        First preferred shares 
        Second preferred shares 
        Common shares 
      Issued -
        13,355,891 common shares (1997 - 13,622,375)                               189,108             192,845
   Contributed surplus                                                                  --                 307
   Deficit                                                                         (17,565)             (7,089)
                                                                                 ---------           ---------
                                                                                   234,946             249,466
                                                                                 ---------           ---------

                                                                                 $ 318,584           $ 285,125
                                                                                 =========           =========
</TABLE>


Approved by the Board:

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



                                       21
<PAGE>   22

CONSOLIDATED STATEMENT OF INCOME (LOSS) AND DEFICIT
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES

<TABLE>
<CAPTION>
Year ended December 31,                                          1998                    1997                  1996
                                                              ------------           ------------           ------------
                                                                 (US$ in thousands except shares and per share amounts)
<S>                                                          <C>                     <C>                    <C>         
Production revenue                                            $     74,861           $     84,219           $     72,838
   Less: Royalties                                                  13,246                 14,592                 12,226
                                                              ------------           ------------           ------------
Production revenue, net of royalties                                61,615                 69,627                 60,612
Interest and other revenue (Note 5)                                  2,776                  2,428                  2,487
                                                              ------------           ------------           ------------
                                                                    64,391                 72,055                 63,099
                                                              ------------           ------------           ------------

Production costs                                                    16,355                 13,325                 12,220
General and administrative expenses                                  4,796                  4,308                  3,972
Interest                                                               437                     --                     --
Depletion and amortization                                          42,081                 36,951                 30,920
Additional depletion: Libyan properties                              5,144                     --                     --
                      UK properties                                  1,100                     --                     --
                                                              ------------           ------------           ------------
                                                                    69,913                 54,584                 47,112
                                                              ------------           ------------           ------------
Income (loss) before income taxes and dividends on
   preferred shares of a subsidiary                                 (5,522)                17,471                 15,987

Income taxes (Note 6):
   Current                                                              14                      7                    124
   Deferred                                                         (1,423)                 7,304                  6,079
                                                              ------------           ------------           ------------
                                                                    (1,409)                 7,311                  6,203
                                                              ------------           ------------           ------------

Income (loss) before dividends on preferred shares
   of a subsidiary                                                  (4,113)                10,160                  9,784

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

Net income (loss) applicable to common shares                       (9,055)                 5,218                  4,842

Deficit, beginning of year                                          (7,089)               (12,307)               (17,149)
Cost of purchase of common shares in excess
   of stated capital (Note 4)                                       (1,421)                    --                     --
                                                              ------------           ------------           ------------

Deficit, end of year                                          $    (17,565)          $     (7,089)          $    (12,307)
                                                              ============           ============           ============

Net income (loss) per common share (Note 7)                   $      (0.67)          $       0.38           $       0.37
                                                              ============           ============           ============

Weighted average number of common shares outstanding            13,480,067             13,620,728             13,065,414
                                                              ============           ============           ============
</TABLE>



                                       22
<PAGE>   23

CONSOLIDATED STATEMENT OF CHANGES IN FINANCIAL POSITION
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES

<TABLE>
<CAPTION>
Year ended December 31,                                            1998               1997              1996
-----------------------                                          --------           --------           --------
                                                                               (US$ in thousands)

<S>                                                              <C>                <C>                <C>     
Operating activities:
   Net income (loss) applicable to common shares                 $ (9,055)          $  5,218           $  4,842
   Items not requiring a current cash outlay:
      Depletion and amortization                                   48,325             36,951             30,920
      Deferred income taxes                                        (1,423)             7,304              6,079
                                                                 --------           --------           --------
   Cash flow from operations                                       37,847             49,473             41,841
   Change in non-cash operating working capital
      Accounts receivable                                          (3,168)               337             (2,936)
      Other current assets                                            324               (313)               199
      Accounts payable and accrued                                    164                992               (901)
      Dividend payable                                                 --                 --             (1,236)
                                                                 --------           --------           --------
                                                                   35,167             50,489             36,967
                                                                 --------           --------           --------

Financing activities:
   Issue of common shares                                             437                975             50,097
   Purchase of common shares for cancellation                      (5,902)              (849)                --
   Increase in long-term debt                                      40,000                 --                 --
   Financing costs                                                     --                 --             (2,440)
                                                                 --------           --------           --------
                                                                   34,535                126             47,657
                                                                 --------           --------           --------

Investing activities:
   Lease acquisition, exploration and development costs           (91,690)           (69,453)           (56,636)
   Purchase of producing gas and oil properties                      (883)                --             (2,077)
   Sale of producing properties                                        --                 --              1,040
                                                                 --------           --------           --------
                                                                  (92,573)           (69,453)           (57,673)
   Purchase of other capital assets                                   (93)              (324)              (187)
   Change in investing accounts payable and accrued                 6,652              3,638              5,110
                                                                 --------           --------           --------
                                                                  (86,014)           (66,139)           (52,750)
                                                                 --------           --------           --------

Change in cash and short-term deposits                            (16,312)           (15,524)            31,874

Cash and short-term deposits, beginning of year                    26,925             42,449             10,575
                                                                 --------           --------           --------

Cash and short-term deposits, end of year                        $ 10,613           $ 26,925           $ 42,449
                                                                 ========           ========           ========
</TABLE>



                                       23
<PAGE>   24

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (December 31, 1998, 1997 and 1996)
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 UK 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 US
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 US accounting principles that affect
        the Company are referred to in Note 11, which provides the effects of
        the 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 US 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 US
        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, all current liabilities and long-term
        debt, the fair values of which approximate their carrying amounts due to
        their short-term or current rate 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.
        Long-term debt is subject to normal floating interest rate risk.

   (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. 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 and are based on
        current engineering estimates in



                                       24
<PAGE>   25


        accordance with current regulations and industry practices. Actual
        costs, when incurred are charged against the abandonment cost accrual.
                A ceiling test is applied to ensure that capitalized costs do
        not exceed estimated future net revenues less certain applicable costs.
        There is uncertainty as to the prices at which gas and oil produced by
        the Company may be sold. The application of such ceiling test to US
        property carrying costs at December 31, 1998, using the $12.27 average
        oil and natural gas liquids ("ngls") price received by the Company
        during the year and the $2.15 December 31, 1998 natural gas price,
        required no write-down. A write-down of $10,614,000, after providing for
        tax recoveries of $5,842,000, would have been required had December 31,
        1998 prices, $2.15 for natural gas and $9.72 for oil and ngls, been
        used. An impairment provision of $2,849,000, after providing for tax
        recoveries of $2,295,000, was recorded in respect of one of the Libyan
        concessions; and a write-down of $609,000, after providing for tax
        recoveries of $491,000, was recorded in respect of the UK properties.
                The following weighted average field prices were used in the
        determination of the Company's US future net revenues for purposes of
        the ceiling test:

<TABLE>
<CAPTION>
        As at December 31,                                        1998             1997           1996
        ------------------                                     ---------       ---------       ---------
        <S>                                                    <C>             <C>             <C>      
        Oil - per barrel                                       $   12.35       $   16.92       $   24.29
                                                               =========       =========       =========
        Ngls - per barrel                                      $   10.19       $   15.14       $   21.66
                                                               =========       =========       =========
        Oil & ngls - per barrel                                $   12.27       $   16.69       $   24.03
                                                               =========       =========       =========
        Natural gas - per thousand cubic feet ("mcf")          $    2.15       $    2.74       $    3.43
                                                               =========       =========       =========
</TABLE>

                A field price of $1.74 (1997 - $1.76; 1996 - $2.04) per thousand
        cubic feet was used in the determination of the Company's UK future net
        revenues for purposes of the ceiling test.
                Depletion rates per physical unit of US production are as
        follows:

<TABLE>
<CAPTION>
                                             Natural Gas   Crude Oil & Ngls
                                              (per mcf)     (per barrel)
                                             -----------   ----------------
        <S>                                  <C>           <C>
        Year ended December 31, 1996          $   1.03       $   6.16
                                              ========       ========
        Year ended December 31, 1997          $   1.11       $   6.68
                                              ========       ========
        YEAR ENDED DECEMBER 31, 1998          $   1.16       $   6.97
                                              ========       ========
</TABLE>

                The depletion rate per physical unit of UK natural gas
        production was $0.81 per mcf for the year ended December 31, 1998
        (1997-$0.81; 1996-$0.56).
                General and administrative costs relating directly to lease
        acquisition, exploration and development activities have been
        capitalized as follows:

<TABLE>
<CAPTION>
        Year ended December 31,     1998            1997            1996
        -----------------------    ------          ------          ------
                                               (in thousands)
        <S>                        <C>             <C>             <C>   
        Lease acquisition          $  857          $  694          $  837
        Exploration                 1,740           1,470           1,547
        Development                 1,715           1,387           1,254
                                   ------          ------          ------
                                   $4,312          $3,551          $3,638
                                   ======          ======          ======
</TABLE>

                At December 31, 1998, Libyan property carrying costs of $9.9
        million (1997 - $14.6 million) were excluded from depletion calculations
        pending evaluation.



                                       25
<PAGE>   26

   (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.

   (h)  COMPARATIVE FIGURES

        Certain 1997 information has been reclassified to conform to the 1998
        presentation.

2. REVOLVING CREDIT AND TERM LOAN AGREEMENTS

   In 1997 the Company arranged an unsecured revolving credit facility with a
   syndicate of banks. The facility, in the amount of $100 million or the
   Canadian dollar equivalent, 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 US base rate, or at Bankers' Acceptance rates or LIBOR plus
   applicable margins. Certain financial tests are required to be met quarterly.
   Under this facility, $40 million was utilized at December 31, 1998, carrying
   a weighted average interest rate of 5.65%. 

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 $25.6042 per share during 1999, 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.



                                       26
<PAGE>   27

4. Share Capital

   (a) COMMON SHARES

<TABLE>
<CAPTION>
   Year ended December 31,                     1998                           1997                            1996
   -----------------------        --------------------------      --------------------------      -------------------------
                                      NUMBER           SHARE          Number          Share           Number          Share
                                          OF         CAPITAL              of         Capital              of        Capital
                                      SHARES         ACCOUNT          shares         Account          shares        Account
                                  ----------     -----------      ----------     -----------      ----------    -----------
                                                                (dollars in thousands)
   <S>                            <C>            <C>              <C>            <C>              <C>           <C>        
   Balance, beginning of year     13,622,375     $   192,845      13,591,763     $   192,381      10,546,100    $   143,635
   Share options exercised            28,216             437          66,912             975          75,663          1,092
   Shares purchased and
      cancelled(*)                  (294,700)         (4,174)        (36,300)           (511)             --             --
   Shares issued for cash(**)             --              --              --              --       2,970,000         47,654
                                  ----------     -----------      ----------     -----------      ----------    -----------
   
   Balance, end of year           13,355,891     $   189,108      13,622,375     $   192,845      13,591,763    $   192,381
                                  ==========     ===========      ==========     ===========      ==========    ===========
</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, 1998, 1,130,875 (1997 - 1,159,091; 1996 - 1,226,003) 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 represented the excess of original net issue price
        over purchase price of shares purchased and cancelled pursuant to issuer
        bids in 1995, 1997 and 1998.

   (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. Each option
        expires not later than ten years from the date it was granted. Options
        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. 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. At December 31,
        1998 options were outstanding to 47 participants in the Plan.



                                       27
<PAGE>   28

        The following is a summary of activity related to the Plan for the years
ended December 31, 1998, 1997 and 1996.

<TABLE>
<CAPTION>
Year ended December 31,                         1998                      1997                       1996
-----------------------                 --------------------       --------------------       --------------------
                                                    WEIGHTED                   Weighted                   Weighted
                                        NUMBER       AVERAGE       Number       Average         Number     Average
                                            OF        OPTION           of        Option             of      Option
                                        SHARES         PRICE       Shares         Price         Shares       Price
                                      ---------     --------       ------      --------         ------       -----
<S>                                   <C>           <C>           <C>          <C>            <C>         <C>     
Outstanding at beginning of year      1,057,673      $16.47       909,253        $15.10       980,250       $14.90
Granted                                  65,000       21.08       228,000         21.35        15,000        23.75
Exercised                               (28,216)      15.49       (66,912)        14.47       (75,663)       14.22
Forfeited                               (10,600)      20.07       (12,668)        16.06       (10,334)       15.39
                                      ---------                 ---------                     -------
Outstanding at end of year            1,083,857       16.74     1,057,673         16.47       909,253        15.10
                                      =========                 =========                     =======

Options exercisable at year end         869,858                   707,738                     558,319
                                      =========                 =========                     =======
</TABLE>

        The following table summarizes information about options outstanding at
December 31, 1998.

<TABLE>
<CAPTION>
                                               Options Outstanding                     Options Exercisable
                                       --------------------------------------          -------------------
                         Range                            Weighted   Weighted                     Weighted
                            of            Number           Average    Average            Number    Average
                        Option                of         Remaining     Option                of     Option
                        Prices            Shares  Contractual Life      Price            Shares      Price
                        ------            ------  ----------------      -----            ------      -----
              <S>                      <C>        <C>                <C>               <C>        <C>
               $13.50 to 15.63           694,523         4.9 years    $ 14.37           694,523    $ 14.37
                18.00 to 20.87           118,334         4.6 years      19.16            93,334      19.47
                21.23 to 23.75           271,000         8.5 years      21.75            82,001      21.67
                                       ---------                                        -------
                                       1,083,857                                        869,858
                                       =========                                        =======
</TABLE>


   5.   INTEREST AND OTHER INCOME

        Interest and other revenue for the first quarter of 1998 included $1.6
        million awarded by the courts pursuant to a successful claim for
        recovery of excess transportation charges incurred from 1990 through
        1997. The award comprises transportation charges, legal fees and
        judgement interest in the amounts of $1,129,000, $282,000 and $189,000,
        respectively.
               

   6.   INCOME TAXES

        Income tax expense is made up of the following components:

<TABLE>
<CAPTION>
Year ended December 31,                          1998                  1997                  1996
-----------------------                  -------------------    ------------------    ------------------
                                         CANADA         US      Canada       US       Canada        US
                                         -------     -------    -------    -------    -------    -------
                                                                 (in thousands)
<S>                                      <C>         <C>        <C>        <C>        <C>        <C>    
Income (loss) before income taxes and
   dividends on preferred shares of a
   subsidiary                            $(6,829)    $ 1,307    $ 2,072    $15,399    $ 1,461    $14,526
                                         =======     =======    =======    =======    =======    =======
Income taxes (recovery)
   Current                                    14          --          7         --        124         --
   Deferred                               (1,740)        317      2,007      5,297        912      5,167
                                         -------     -------    -------    -------    -------    -------
                                         $(1,726)    $   317    $ 2,014    $ 5,297    $ 1,036    $ 5,167
                                         =======     =======    =======    =======    =======    =======
</TABLE>



                                       28
<PAGE>   29
                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,                             1998                    1997                    1996
-----------------------                     -------------------     -------------------     -------------------
                                             CANADA       US        Canada        US        Canada        US
                                            -------     -------     -------     -------     -------     -------
                                                                       (in thousands)
<S>                                         <C>         <C>         <C>         <C>         <C>         <C>    
Amortization of buildings and equipment     $   (27)    $    18     $  (112)    $  (275)    $     3     $   340
Depletion of natural resource properties     (2,073)      6,104         (68)      6,011         805       5,898
Financing costs                                 243          --         338          --         348          --
Tax loss carry forward                          154      (5,839)      1,846        (430)       (230)     (1,143)
Other                                           (37)         34           3          (9)        (14)         72
                                            -------     -------     -------     -------     -------     -------
                                            $(1,740)    $   317     $ 2,007     $ 5,297     $   912     $ 5,167
                                            =======     =======     =======     =======     =======     =======
</TABLE>

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

<TABLE>
<CAPTION>
Year ended December 31,                                     1998         1997         1996
-----------------------                                    -------      -------      -------
                                                                    (in thousands)
<S>                                                        <C>          <C>          <C>
Tax at statutory rate of 44.62%
   (Combined Canadian federal and provincial rate)         $(2,465)     $ 7,796      $ 7,133
Add (deduct) the effect of:
   Lower income tax rate on earnings of US subsidiaries        (81)      (1,373)      (1,263)
   Canadian income tax on exchange loss (gain) which is
      eliminated upon consolidation                            511          362          (56)
   Other                                                       626          526          389
                                                           -------      -------      -------
Tax at effective rate                                      $(1,409)     $ 7,311      $ 6,203
                                                           =======      =======      =======
Effective tax rate                                            25.5%        41.8%        38.8
                                                           =======      =======      =======
</TABLE>

   7.   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.

   8.   PERSON COSTS AND OBLIGATIONS

The Company contributed $145,300, $144,254 and $103,455 for 1998, 1997 and 1996,
respectively, to defined contribution plans. Under a supplementary defined
contribution plan established in 1991, costs of $198,294, $162,384 and $127,358
for 1998, 1997 and 1996, respectively, and the related liability are recorded in
the accounts.

        The Company has established no other retirement benefit plans.



                                       29
<PAGE>   30
9.   DISAGGREGATED INFORMATION

The Company has only a single reportable segment with activities as explained in
the preamble to the Notes. Production revenue, net of royalties, all of which
arises from external customers, is attributed to the country in which the
underlying production occurred. Most of the US gas, oil and ngls produced by the
Company are marketed by a single aggregator. Production revenues, net of
royalties, associated with the aggregator were $46,340,000 (1997 - $50,250,000;
1996 - $43,611,000). The Company's oil production from the Aneth and Ratherford
Units in the Four Corners area of Utah is sold under successive term contracts
to a regional refiner. Production revenues, net of royalties, associated with
sales to the regional refiner were $8,207,000 (1997 - $10,880,000; 1996 -
$10,641,000). The Company believes that alternative marketing arrangements would
be readily available for its gas, oil and liquids.

<TABLE>
<CAPTION>
                                                           1998              1997              1996
                                                         --------          --------          --------
                                                                      (in thousands)
<S>                                                     <C>              <C>                <C>
Production revenue, net of royalties
   United States                                         $ 56,199          $ 63,227          $ 56,457
   United Kingdom                                           4,411             6,231             4,155
   Libya                                                    1,005               169                 -
                                                         --------          --------          --------
Total production revenues, net of royalties                61,615            69,627            60,612
Interest and other revenue                                  2,776             2,428             2,487
                                                         --------          --------          --------
                                                         $ 64,391          $ 72,055          $ 63,099
                                                         ========          ========          ========

Net capital assets
   United States                                         $267,020          $213,856          $176,672
   United Kingdom                                          11,337            14,733            17,778
   Libya                                                    9,835            14,373            13,297
   Canada and other                                           285               328               305
                                                         --------          --------          --------
                                                         $288,477          $243,290          $208,052
                                                         ========          ========          ========
</TABLE>


10.  UNCERTAINTY DUE TO THE YEAR 2000

During the past three years the Company has made changes to its computer systems
in order that date related information can be processed correctly after December
31, 1999 and the Company believes that such capability will be attained with
respect to its internal systems.
        Despite these efforts, it is not possible to be certain that all aspects
of the year 2000 issue affecting the Company, including those related to the
provision of goods and services by third parties, will be fully resolved before
the year 2000.



                                       30
<PAGE>   31

11.  UNITED STATES ACCOUNTING PRINCIPLES

 (a) FULL COST ACCOUNTING

     US full cost accounting rules differ materially from the Canadian full
     cost accounting guidelines followed by the Company. In determining the
     limitation on carrying values, US 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 and financing costs. During 1998 an impairment adjustment
     would have been required under US accounting rules. The quarterly test
     required by US accounting rules, using December 31 US gas and oil prices
     of $2.15 per mcf and $9.72 per barrel, and June 30 US gas and oil prices
     of $2.09 per mcf and $12.40 per barrel to determine future net revenues,
     would have resulted in a write-down of US property carrying costs of
     $42.6 million, after providing for tax recoveries of $22.9 million, at
     December 31; and $16.1 million, after providing for tax recoveries of
     $8.6 million, at June 30. Under Canadian guidelines the test resulted in
     a write-down of UK property carrying costs of $0.6 million, after
     providing for tax recoveries of $0.5 million; no corresponding
     write-down was required under US accounting rules. Such write-downs will
     result in reduced depletion expense, under US rules, for subsequent
     periods.

 (b) INCOME TAXES

     US 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.

 (c) EARNINGS PER SHARE

     US accounting principles require share options to be included in fully
     diluted earnings (loss) per common share, where dilutive, assuming that
     the share options are exercised using the treasury stock method.

 (d) EFFECT ON EARNINGS

     The effect on consolidated earnings of the differences between Canadian
     and US accounting principles is summarized as follows:

     <TABLE>
     <CAPTION>
     Year ended December 31,                                                   1998             1997             1996
     -----------------------                                               ------------     ------------     ------------
                                                                         (in thousands except shares and per share amounts)
     <S>                                                                   <C>              <C>              <C>         
     Net income (loss) applicable to common shares, as reported            $     (9,055)    $      5,218     $      4,842
     Additional depletion                                                       (89,153)              --               --
                                                                           ------------     ------------     ------------
                                                                                (98,208)           5,218            4,842
     Reduction in depletion expense                                               4,235            3,177            2,381
     Reduction (increase) in deferred tax provision                              30,010             (885)          (1,021)
                                                                           ------------     ------------     ------------
     Net income (loss) applicable to common shares under US
        accounting principles                                              $    (63,963)    $      7,510     $      6,202
                                                                           ============     ============     ============
     Net income (loss) per common share under US accounting principles:
           Basic                                                           $      (4.75)    $       0.55     $       0.47
                                                                           ============     ============     ============
           Fully diluted                                                   $      (4.75)    $       0.54     $       0.46
                                                                           ============     ============     ============
     
     Fully diluted number of common shares outstanding                       13,480,067       13,858,593       13,446,684
                                                                           ============     ============     ============
     </TABLE>
     
     
     
                                       31
<PAGE>   32

 (e) EFFECT ON BALANCE SHEET

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

     <TABLE>
     <CAPTION>
     As at December 31,                   1998                          1997
     ------------------                   ----                          ----
                                                UNDER US                    Under US
                                        AS    ACCOUNTING            As    Accounting
                                  REPORTED    PRINCIPLES      Reported    Principles
                                 ---------     ---------     ---------     --------- 
                                                   (in thousands)
     <S>                         <C>           <C>           <C>           <C>      
     Net capital assets          $ 288,477     $ 185,517     $ 243,290     $ 225,248
     Deferred tax - asset        $   5,182     $  28,233     $   3,442     $   5,537
     Deferred tax - liability    $  13,684     $      --     $  13,367     $   8,737
     Deficit                     $ (17,565)    $ (83,790)    $  (7,089)    $ (18,406)
     </TABLE>

     Additionally for US reporting purposes, the preferred shares shown as
     shareholders' equity in these consolidated financial statements would be
     shown outside the equity section.

 (f) INCOME TAX DISCLOSURES

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

     <TABLE>
     <CAPTION>
     As at December 31,                               1998               1997
     ------------------                             --------           -------- 
                                                           (in thousands)
     <S>                                            <C>                <C>
     Deferred tax assets
        Depletion and amortization                  $  6,971           $  3,413
        Financing costs                                  390                633
        Loss carryforwards                            20,593             14,908
        Other                                            382                346
                                                    --------           -------- 
                                                      28,336             19,300
     Deferred tax liabilities
        Depletion and amortization                        --            (22,431)
        Other                                           (103)               (69)
                                                    --------           -------- 
                                                        (103)           (22,500)
                                                    --------           -------- 
     
     Net deferred tax assets (liabilities)          $ 28,233           $ (3,200)
                                                    ========           ======== 
     </TABLE>


     At December 31, 1998 the Company's US net operating tax losses carried
     forward amounted to $55,218,000 of which $6,119,000, $2,835,000,
     $6,139,000, $18,007,000, $3,773,000, $2,090,000 and $16,255,000 expire in
     the years 2005, 2007, 2009, 2010, 2011, 2012 and 2018, respectively.
     Canadian net operating tax losses carried forward amounted to $2,231,000 of
     which $1,998,000 and $233,000 expire in the years 2003 and 2005,
     respectively. The Company is of the opinion that the tax benefit of these
     tax losses will be realized. 



                                       32
<PAGE>   33

         Provisions for deferred income taxes are as follows:

        <TABLE>
        <CAPTION>
        Year ended December 31,                            1998                        1997                      1996
        -----------------------                   ----------------------      ---------------------     ---------------------
                                                   CANADA          US          Canada         US         Canada         US
                                                  --------      --------      --------     --------     --------     --------
                                                                                   (in thousands)
        <S>                                       <C>           <C>           <C>          <C>          <C>          <C>     
        Income (loss) before income taxes and
           dividends on preferred shares of
           a subsidiary                           $ (5,002)     $(85,440)     $  3,019     $ 17,629     $  1,962     $ 16,406
                                                  ========      ========      ========     ========     ========     ========
        
        Provision for deferred income taxes       $   (921)     $(30,512)     $  2,122     $  6,067     $  1,239     $  5,861
                                                  ========      ========      ========     ========     ========     ========
        </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,                                    1998           1997           1996
        -----------------------                                  --------       --------       --------
                                                                              (in thousands)
        <S>                                                      <C>            <C>            <C>     
        Tax at statutory Canadian rate of 44.6%                  $(40,355)      $  9,213       $  8,196
        Lower income tax rate on earnings of US subsidiaries        7,830         (1,617)        (1,428)
        Canadian income tax on exchange loss (gain) which is
           eliminated upon consolidation                              511            362            (56)
        Other                                                         595            238            512
                                                                 --------       --------       --------
        Tax at effective rate                                    $(31,419)      $  8,196       $  7,224
                                                                 ========       ========       ========
        
        Effective tax rate                                           34.7%          39.7%          39.3%
                                                                 ========       ========       ========
        </TABLE>
        
        
   (g)  STOCK-BASED COMPENSATION

        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. US 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 and resulting in option
        fair values of $10.61, $11.49 and $12.54, applying risk-free interest
        rates of 5.64%, 6.85% and 6.51% for options granted in 1998, 1997 and
        1996, respectively, and assuming ten year expected option lives, no
        dividend yields and expected volatilities of 25%, 24% and 24% on a
        weighted average basis, would amount to a net of tax charge to income
        (loss) of $1,502,000 (1997 - $1,348,000; 1996 - $872,000). After
        reflecting this charge, pro forma net income (loss) applicable to common
        shares under US accounting principles would be $(65,465,000), (1997 -
        $6,162,000; 1996 - $5,330,000); pro forma net income (loss) per common
        share under US accounting principles would be $(4.86) (1997 - $0.45;
        1996 - $0.41); and pro forma fully diluted earnings (loss) per common
        share under US accounting principles would be $(4.86) (1997 - $0.45;
        1996 - $0.40). These effects are not necessarily indicative of those to
        be expected in future years.

   (h)  SUPPLEMENTAL CASH FLOW INFORMATION

        Net cash outflows for income taxes for the years 1998, 1997 and 1996
        were $14,000, $141,000 and $26,000, respectively. Cash outflows for
        long-term debt interest were $628,000 in 1998.



                                       33
<PAGE>   34

                      SUPPLEMENTARY FINANCIAL INFORMATION
             CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
                               DECEMBER 31, 1998
(Unaudited)

RESERVE INFORMATION

Reports prepared by Netherland, Sewell & Associates, Inc. as to the Company's US
reserves and by the Company as to the UK 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>
                                                                                                       Crude Oil &
                                                                 Natural Gas - mmcf              Ngls - barrels(*)
                                                       ------------------------------------      -----------------
                                                        United         North                               United
                                                        States           Sea          Total                States
                                                       -------        ------        -------            ----------
<S>                                                    <C>            <C>           <C>                <C>       
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
   PURCHASE OF PRODUCING PROPERTIES                      4,745            --          4,745                18,600
   REVISION OF PREVIOUS ESTIMATES                       10,683        (5,119)         5,564            (1,478,900)
   EXTENSIONS, DISCOVERIES AND OTHER ADDITIONS          29,360            --         29,360             4,871,800
   SALE OF PROVED PROPERTIES                                --            --             --                    --
   PRODUCTION                                          (26,960)       (3,088)       (30,048)           (1,158,100)
                                                       -------        ------        -------            ----------
DECEMBER 31, 1998                                      148,954        10,110        159,064            15,200,100
                                                       =======        ======        =======            ==========
</TABLE>

TOTAL PROVED RESERVES AFTER ROYALTY DEDUCTIONS:

<TABLE>
<CAPTION>
                                                                                                       Crude Oil &
                                                                 Natural Gas - mmcf              Ngls - barrels(*)
                                                       ------------------------------------      -----------------
                                                        United         North                               United
                                                        States           Sea          Total                States
                                                       -------        ------        -------            ----------
<S>                                                    <C>            <C>           <C>                 <C>      
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
   PURCHASE OF PRODUCING PROPERTIES                      3,512            --          3,512                13,800
   REVISION OF PREVIOUS ESTIMATES                        7,819        (5,119)         2,700            (1,316,000)
   EXTENSIONS, DISCOVERIES AND OTHER ADDITIONS          22,268            --         22,268             4,142,300
   SALE OF PROVED PROPERTIES                                --            --             --                    --
   PRODUCTION                                          (21,416)       (3,088)       (24,504)             (986,800)
                                                       -------        ------        -------            ----------
DECEMBER 31, 1998                                      118,963        10,110        129,073            13,107,100
                                                       =======        ======        =======            ==========
</TABLE>

(*) 26,800 (1997 - 58,900) barrels of natural gas liquids, before and after
royalty deductions, associated with the UK gas reserves are not included in this
table.



                                       34
<PAGE>   35

(Unaudited)

        PROVED DEVELOPED PRODUCING RESERVES BEFORE ROYALTY DEDUCTIONS:

<TABLE>
<CAPTION>
                                                                          Crude Oil &
                                    Natural Gas - mmcf              Ngls - barrels(*)
                          ------------------------------------      -----------------
                          United         United                                United
                          States        Kingdom          Total                 States
                          ------        -------          -----              --------- 
<S>                       <C>           <C>             <C>                 <C>      
December 31, 1996         53,400         23,364         76,764              9,175,900
                          ======         ======         ======              =========
December 31, 1997         55,013         18,317         73,330              8,209,000
                          ======         ======         ======              =========
DECEMBER 31, 1998         70,082         10,108         80,190              5,430,000
                          ======         ======         ======              =========
</TABLE>

        PROVED DEVELOPED PRODUCING RESERVES AFTER ROYALTY DEDUCTIONS:

<TABLE>
<CAPTION>
                                                                          Crude Oil &
                                    Natural Gas - mmcf              Ngls - barrels(*)
                          ------------------------------------      -----------------
                          United         United                                United
                          States        Kingdom          Total                 States
                          ------        -------          -----                 ------ 
<S>                       <C>            <C>            <C>                 <C>      
December 31, 1996         43,000         23,364         66,364              8,138,000
                          ======         ======         ======              =========
December 31, 1997         43,979         18,317         62,296              7,241,300
                          ======         ======         ======              =========
DECEMBER 31, 1998         55,418         10,108         65,526              4,739,000
                          ======         ======         ======              =========
</TABLE>

RESULTS OF OPERATIONS FOR GAS AND OIL PRODUCING ACTIVITIES

<TABLE>
<CAPTION>
Year ended December 31,                                                      1998          1997          1996
-----------------------                                                    --------      --------      --------
                                                                                       (in thousands)
<S>                                                                        <C>           <C>           <C>     
United States
   Revenue - net of royalties                                              $ 56,199      $ 63,227      $ 56,457
   Production costs                                                         (15,675)      (14,901)      (13,291)
   Depletion and amortization                                               (39,460)      (33,414)      (28,976)
                                                                           --------      --------      --------
   Results of operations from producing activities before income taxes        1,064        14,912        14,190
   Income tax expense                                                          (333)       (5,223)       (5,146)
                                                                           --------      --------      --------
    Results of operations from producing activities after income taxes     $    731      $  9,689      $  9,044
                                                                           ========      ========      ========

United Kingdom
   Revenue - net of royalties                                              $  4,411      $  6,231      $  4,155
   Production costs                                                            (964)       (1,064)         (904)
   Depletion and amortization                                                (3,646)       (3,319)       (1,861)
                                                                           --------      --------      --------
   Results of operations from producing activities before income taxes         (199)        1,848         1,390
   Income tax expense                                                           117          (787)         (600)
                                                                           --------      --------      --------
    Results of operations from producing activities after income taxes     $    (82)     $  1,061      $    790
                                                                           ========      ========      ========

Libya
   Revenue - net of royalties                                              $  1,005      $    169      $     --
   Production costs                                                          (1,041)          (38)           --
   Depletion and amortization                                                (5,144)         (131)           --
                                                                           --------      --------      --------
   Results of operations from producing activities before income taxes       (5,180)           --            --
   Income tax expense                                                         2,312            --            --
                                                                           --------      --------      --------
    Results of operations from producing activities after income taxes     $ (2,868)     $     --      $     --
                                                                           ========      ========      ========

Total
   Revenue - net of royalties                                              $ 61,615      $ 69,627      $ 60,612
   Production costs                                                         (17,680)      (16,003)      (14,195)
   Depletion and amortization                                               (48,250)      (36,864)      (30,837)
                                                                           --------      --------      --------
   Results of operations from producing activities before income taxes       (4,315)       16,760        15,580
   Income tax expense                                                         2,096        (6,010)       (5,746)
                                                                           --------      --------      --------
    Results of operations from producing activities after income taxes     $ (2,219)     $ 10,750      $  9,834
                                                                           ========      ========      ========
</TABLE>



                                       35
<PAGE>   36

(Unaudited)

CAPITALIZED COSTS RELATING TO GAS AND OIL EXPLORATION AND PRODUCTION ACTIVITIES

<TABLE>
<CAPTION>
December 31,                                              1998         1997         1996
------------                                            --------     --------     --------
                                                                   (in thousands)
<S>                                                     <C>          <C>          <C>     
Proved gas and oil properties                           $475,902     $402,885     $337,538
Unproved gas and oil properties                           76,478       56,922       52,816
                                                        --------     --------     --------
                                                         552,380      459,807      390,354
Accumulated depletion                                    266,066      224,154      187,403
                                                        --------     --------     --------
Net capitalized costs                                   $286,314     $235,653     $202,951
                                                        ========     ========     ========
</TABLE>

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

<TABLE>
<CAPTION>
Year ended December 31,                                   1998         1997        1996
-----------------------                                 --------     --------     --------
                                                                  (in thousands)
<S>                                                     <C>          <C>          <C>     
Property acquisition costs:
   United States                                        $  7,903     $  9,164     $ 13,954
   United Kingdom                                            115          137          722
   Other Foreign                                              --           --           68
                                                        --------     --------     --------
                                                           8,018        9,301       14,744
                                                        --------     --------     --------
Purchase of producing properties:
   United States                                             883           --        2,077
                                                        --------     --------     --------
Sale of producing properties:
   United States                                              --           --       (1,040)
                                                        --------     --------     --------
Exploration costs:
   United States                                          43,317       35,540       17,453
   United Kingdom                                             72          115           --
   Other Foreign                                             606        1,207          434
                                                        --------     --------     --------
                                                          43,995       36,862       17,887
                                                        --------     --------     --------
Development costs:
   United States                                          39,606       23,260       22,131
   United Kingdom                                             71           30        1,874
                                                        --------     --------     --------
                                                          39,677       23,290       24,005
                                                        --------     --------     --------
                                                        $ 92,573     $ 69,453     $ 57,673
                                                        ========     ========     ========
</TABLE>



                                       36
<PAGE>   37

(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                                                             1998            1997          1996
-----------                                                           ---------      ---------      ---------
                                                                                   (in thousands)
<S>                                                                   <C>            <C>            <C>      
United States
   Future cash inflows                                                $ 382,771      $ 480,669      $ 577,313
   Future production costs                                             (116,976)      (121,380)      (148,061)
   Future development costs                                             (60,203)       (57,208)       (39,375)
   Future income tax expense                                                 --        (46,742)       (85,464)
                                                                      ---------      ---------      ---------
   Future net cash flows                                                205,592        255,339        304,413
   Ten percent annual discount for estimated timing of cash flows       (62,089)       (70,844)       (89,292)
                                                                      ---------      ---------      ---------
   Standardized measure of discounted future net cash flows             143,503        184,495        215,121
                                                                      ---------      ---------      ---------

United Kingdom
   Future cash inflows                                                   19,349         32,774         48,392
   Future production costs                                               (7,483)        (5,734)        (8,045)
   Future development costs                                              (1,457)        (1,338)        (1,603)
   Future income tax expense                                                 --         (6,340)        (6,601)
                                                                      ---------      ---------      ---------
   Future net cash flows                                                 10,409         19,250         32,143
   Ten percent annual discount for estimated timing of cash flows        (1,404)        (4,172)        (8,241)
                                                                      ---------      ---------      ---------
   Standardized measure of discounted future net cash flows               9,005         15,078         23,902
                                                                      ---------      ---------      ---------

Total
   Future cash inflows                                                  402,120        513,443        625,705
   Future production costs                                             (124,459)      (127,114)      (156,106)
   Future development costs                                             (61,660)       (58,658)       (40,978)
   Future income tax expense                                                 --        (53,082)       (92,065)
                                                                      ---------      ---------      ---------
   Future net cash flows                                                216,001        274,589        336,556
   Ten percent annual discount for estimated timing of cash flows       (63,493)       (54,856)       (97,533)
                                                                      ---------      ---------      ---------
   Standardized measure of discounted future net cash flows           $ 152,508      $ 199,573      $ 239,023
                                                                      =========      =========      =========
</TABLE>



                                       37
<PAGE>   38

(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,                              1998           1997           1996
-----------------------                            ---------      ---------      ---------
                                                                (in thousands)
<S>                                                <C>            <C>            <C>       
Sales of oil, ngls and natural gas produced,
   net of production costs                         $ (45,231)     $ (56,061)     $ (48,233)
Net change in prices and production costs            (79,471)       (73,047)       120,858
Extensions and discoveries, less related costs        30,159         28,219         50,995
Purchase of producing properties                       2,793             --         10,638
Sales of producing properties                             --             --           (436)
Development costs incurred during the period          23,131         10,096         15,026
Revisions of previous quantity estimates             (17,191)        22,388         (4,462)
Accretion of discount                                 19,958         23,902         15,457
Net change in income taxes                            38,739         26,534        (51,064)
Changes in estimated future development costs        (16,421)       (12,551)       (13,950)
Other                                                 (3,531)        (8,930)         6,700
                                                   ---------      ---------      ---------

Net increase (decrease)                              (47,065)       (39,450)       101,529
Beginning of year                                    199,573        239,023        137,494
                                                   ---------      ---------      ---------

End of year                                        $ 152,508      $ 199,573      $ 239,023
                                                   =========      =========      =========
</TABLE>

QUARTERLY FINANCIAL INFORMATION

<TABLE>
<CAPTION>
                                                                  Per
                                     Gross      Income         Common
Quarter Ended          Revenue      Profit       (loss)         Share
-------------          -------     -------      -------      --------
                          (in thousands except per share amounts)
<S>                    <C>         <C>          <C>          <C>     
MARCH 31,1998          $18,718     $ 2,884      $   556      $   0.04
JUNE 30,1998            14,804        (342)      (1,735)        (0.13)
SEPTEMBER 30,1998       13,943      (1,345)      (2,472)        (0.18)
DECEMBER 31,1998        16,926      (6,719)      (5,404)        (0.40)

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
</TABLE>



                                       38
<PAGE>   39


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 11, 1999 for the annual meeting of shareholders on May 13, 1999.

ITEM 11. EXECUTIVE COMPENSATION

"Executive Compensation" on pages 5 to 9 of the Company's Information Circular
dated March 11, 1999 for the annual meeting of shareholders on May 13, 1999 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 11, 1999 for the annual meeting of shareholders
on May 13, 1999 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 19 of this report.

EXHIBITS

Reference is made to the Index to Exhibits on page 40 of this report.




                                       39

<PAGE>   40


                                    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 11, 1999 relating to the Company's annual meeting of shareholders
                      to be held on May 13, 1999.
 ******   22          Subsidiaries of the Company.
  *****   24 (a)      Consent of Netherland, Sewell & Associates, Inc.
  *****   24 (b)      Consent of PricewaterhouseCoopers LLP.

      *  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.
   ****  Previously filed as an exhibit to Form 10-K dated March 20, 1998.
  *****  Filed herewith.
 ******  Previously filed as an exhibit to Form 10-K dated March 17, 1994.
</TABLE>



                                       40
<PAGE>   41

                                    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.

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
    Chief Executive Officer                     and Treasurer and Chief 
                                                Financial Officer
Dated:    March 11,1999

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>
<CAPTION>
<S>                                 <C>                                         <C>
     /s/ D. E. MITCHELL             Director                                    March 11, 1999
---------------------------------
     D. E. Mitchell O.C.

      /s/ S. A. MILNER              President, Chief Executive Officer and      March 11, 1999
------------ --------------------   Director
  S. A. Milner, A.O.E., LL.D.     

      /s/ S. C. HURLEY              Director                                    March 11, 1999
---------------------------------
        S. C. Hurley

       /s/ H. J. KELLY              Director                                    March 11, 1999
---------------------------------
         H. J. Kelly

      /s/ J. E. MAYBIN              Director                                    March 11, 1999
---------------------------------
        J. E. Maybin

      /s/ L. G. MUNIN               Director                                    March 11, 1999
---------------------------------
        L. G. Munin

     /s/ E. S. ONDRACK              Director                                    March 11, 1999
---------------------------------
        E. S. Ondrack

      /s/ S. T. PEELER              Director                                    March 11, 1999
---------------------------------
         S. T. Peeler

       /s/ E. L. HAHN               Senior Vice President, Finance and          March 11, 1999
---------------------------------   Treasurer and Chief Financial Officer
         E. L. Hahn

      /s/ R. J. STEFURE             Vice President, Controller and              March 11, 1999
---------------------------------   Chief Accounting Officer
        R. J. Stefure              
</TABLE>



                                       41
<PAGE>   42


                               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 11, 1999 relating to the Company's annual meeting of shareholders
                      to be held on May 13, 1999.
 ******   22          Subsidiaries of the Company.
  *****   24 (a)      Consent of Netherland, Sewell & Associates, Inc.
  *****   24 (b)      Consent of PricewaterhouseCoopers LLP.

      *  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.
   ****  Previously filed as an exhibit to Form 10-K dated March 20, 1998.
  *****  Filed herewith.
 ******  Previously filed as an exhibit to Form 10-K dated March 17, 1994.
</TABLE>