<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, 1999

                        Commission File number 1-10216:

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

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

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:

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

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

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

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

The aggregate market value of the voting stock of Chieftain International, Inc.
held by non-affiliates of said registrant on March 14, 2000 was
U.S.$265,825,098.

The number of shares outstanding of the common stock of Chieftain International,
Inc. on March 14, 2000 was 16,224,059.

                      DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Chieftain International, Inc. Information Circular dated March
15, 2000 for its annual meeting of shareholders to be held on May 25, 2000, are
incorporated by reference into Part III hereof, to the extent indicated herein.
The Exhibits Index can be found on page 56 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.
                          1999 FORM 10-K ANNUAL REPORT

                               Table of Contents


<TABLE>
<CAPTION>
                                                                                                           Page
<S>                                                                                                        <C>
                                                    PART I

  Item 1.   Business .....................................................................................    1
               Segment Information .......................................................................    1
               Properties ................................................................................    2
               Acreage ...................................................................................    6
               Gas and Oil Capital Expenditures ..........................................................    6
               Drilling Activity .........................................................................    7
               Wells .....................................................................................    7
               Reserves ..................................................................................    7
               Production Volumes, Prices and Costs ......................................................    8
               Employees .................................................................................    8
               Business Risks ............................................................................    8
               Glossary ..................................................................................   11
  Item 2.   Properties ...................................................................................   12
  Item 3.   Legal Proceedings ............................................................................   12
  Item 4.   Submission of Matters to a Vote of Security Holders ..........................................   12
               Executive Officers of the Registrant ......................................................   12

                                                    PART II

  Item 5.   Market for the Registrant's Securities and Related Stockholder Matters .......................   13
  Item 6.   Selected Consolidated Financial Data .........................................................   14
  Item 7.   Management's Discussion and Analysis of Financial Condition and Results of Operations ........   15
  Item 8.   Financial Statements and Supplementary Data ..................................................   29
  Item 9.   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure .........   55

                                                    PART III

  Item 10.  Directors and Executive Officers .............................................................   55
  Item 11.  Executive Compensation .......................................................................   55
  Item 12.  Security Ownership of Certain Beneficial Owners and Management ...............................   55
  Item 13.  Certain Relationships and Related Transactions ...............................................   55

                                                    PART IV

  Item 14.  Exhibits and Reports on Form 8-K .............................................................   55

Signatures  ..............................................................................................   57

</TABLE>
<PAGE>   3
                                     PART I


ITEM 1. BUSINESS

Chieftain is an independent energy company engaged in the exploration,
development and production of natural gas and oil. Our producing properties and
exploration acreage are primarily located in the shallow waters of the U.S.
Gulf of Mexico. We also have properties located onshore in Louisiana, in the
Four Corners area of southeast Utah and in the U.K. sector of the North Sea. We
were incorporated under the Business Corporations Act (Alberta) in 1988 and
commenced operations upon the closing of our initial public offering on April
20, 1989.

We have a large natural gas and oil lease acreage position in the Gulf of
Mexico. Our lease interests in the Gulf of Mexico include a balanced portfolio
of exploration and development drilling prospects. These prospects range from
high-impact prospects with relatively greater risks, which we believe have the
potential to add substantially to our reserves, to relatively lower risk
development and exploitation projects with lower reserve potential. Our
exploration efforts are supported by an extensive 3-D seismic database covering
most of our leases. We believe that our seismic database and related
technological expertise have contributed to our successful exploration and
development track record. We believe our conservative capital structure
provides us with the financial flexibility to take advantage of our prospects
and other opportunities, including acquisitions of leasehold acreage and
producing properties.

We hold interests in 129 lease blocks located on the continental shelf of the
Gulf of Mexico. We also have interests in ten deep-water blocks. Of these lease
blocks, 93 are held as exploratory acreage and 46 are held by production. We
operate 39 of these blocks. Our average working interest in our Gulf of Mexico
leases is approximately 40%. In 1999, we had production of 88.6 mmcfe per day
(71.0 mmcfe per day after royalties) in the Gulf of Mexico, which represented
approximately 78% of our total production.

In addition to our Gulf of Mexico properties, we own various interests in two
large light oil producing units in the Four Corners area of southeast Utah
where we had production of 2,026 barrels per day (1,770 barrels per day after
royalties) in 1999. We own an interest in approximately 9,600 net acres in the
U.K. sector of the North Sea where we had production of 10.0 mmcfe per day
(before and after royalties) in 1999. We are also active in exploratory
activities onshore in Louisiana.

At December 31, 1999, we had estimated proved reserves of 290.3 bcfe (239.7 bcfe
after royalties). These reserves had a present value of net cash flows before
income taxes, discounted at 10%, of $266.5 million using constant natural gas
and oil prices in effect on December 31, 1999, which averaged $2.51 per mcf for
U.S. natural gas, $0.99 per mcf for U.K. natural gas and $20.40 per barrel for
oil. At December 31, 1999, approximately 64% of our proved reserves were natural
gas and approximately 63% of our proved reserves were developed. Our total
proved reserves at December 31, 1999 had a reserves-to-production ratio of
approximately 7.1 years.

SEGMENT INFORMATION

Reference is made to page 42 hereof for financial information with respect to
the geographic segments of Chieftain for the years ended December 31, 1999, 1998
and 1997.


---------------------------
* Unless the context indicates another meaning, the terms "Chieftain", "the
Company", "we", "us" and "our" refer to Chieftain International, Inc., a company
organized under the laws of the Province of Alberta, Canada, 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.


                                       1
<PAGE>   4


PROPERTIES

Our principal natural gas and oil properties are concentrated in the U.S. Gulf
of Mexico and, to a lesser extent, onshore Louisiana, Utah and other parts of
the U.S. and in the U.K. sector of the North Sea.

The following table summarizes our estimated proved reserves by major operating
area and the estimated present value of net cash flows before income taxes,
discounted at 10%, of these reserves at December 31, 1999:


<TABLE>
<CAPTION>


                                                                                                             Estimated
                                            Proved reserves (before royalties)                          present value before
                                ----------------------------------------------------------                income taxes of
                                Natural gas             Oil and ngls                Total                  proved reserves
                                  (mmcf)                   (mbbls)                 (mmcfe)              (U.S.$ in thousands)
                                -----------             -------------             --------              ---------------------
<S>                            <C>                     <C>                       <C>                     <C>

Gulf of Mexico..............        131,098                    5,504              164,122                           $186,039
Onshore Louisiana...........         47,083                      158               48,031                             42,283
Utah and Other Onshore......          1,729                   11,648               71,617                             36,040
                                   --------                  -------              -------                          ---------
  Total U.S. ...............        179,910                   17,310              283,770                            264,362
U.K. (North Sea)............          6,376                       20                6,496                              2,112
                                   --------                  -------              -------                          ---------
  Total.....................        186,286                   17,330              290,266                           $266,474
                                   ========                  =======             ========                          =========

</TABLE>

GULF OF MEXICO

We concentrate our exploration and production activities in, and devote
substantial managerial and financial resources to, the offshore U.S. Gulf of
Mexico. The Gulf of Mexico contains a prolific oil and natural gas basin. This
area is more than 600 miles long and 100 miles wide and extends from the State
of Texas to the State of Florida. We primarily focus our exploration and
development activities in the shallow waters (less than 600 feet deep) of the
Gulf of Mexico continental shelf. The continental shelf is a low cost operating
environment for which technical and analytical data, including 3D seismic data,
are readily available. The vast network of gathering systems and pipelines in
the shallow waters of the basin provides excellent access to markets. The Gulf
of Mexico's geology is generally characterized by multiple productive horizons
and good permeability which is conducive to high initial production and
relatively rapid capital payback.

We maintain a large acreage position in the Gulf of Mexico. With an average
interest of 40% in 139 blocks, we rank as the ninth largest independent
producer on the continental shelf. Of these lease blocks, 129 are shallow water
blocks and ten are deep-water blocks. We acquired three blocks covering 15,000
acres at the March 1999 Central Gulf of Mexico lease sale. We participated in
high bids for three blocks, covering 17,000 acres, at the Western Gulf of
Mexico lease sale in late August 1999. Our acreage in the Gulf of Mexico
covered 661,410 (266,249 net) acres at December 31, 1999. We operate 39 blocks
in the Gulf of Mexico.

Described below are the areas of our current exploration and development
activity in the Gulf of Mexico.

     WESTERN GULF (OFFSHORE TEXAS)

MUSTANG ISLAND:

<TABLE>
<CAPTION>

     Blocks         Gross Acres       Net Acres         Average Interest          Average Production         Average Production
     ------        -------------      ---------         ----------------          ------------------         ------------------
                                                                                  (before royalties)          (after royalties)
     <S>           <C>                <C>               <C>                       <C>                         <C>

      5               21,818           10,549               48%                      9.3 mmcf/d                  7.7 mmcf/d

</TABLE>

Most of our production in this area comes from Block 784 (Chieftain 50%) where a
well was successfully recompleted, maintaining production rates at prior year's
levels. No significant exploration or development work was done in 1999 and
none is currently planned for 2000.



                                       2
<PAGE>   5
MATAGORDA ISLAND:

<TABLE>

<CAPTION>
          Blocks      Gross Acres       Net Acres       Average Interest       Average Production       Average Production
          ------      -----------       ---------       ----------------       ------------------       ------------------
                                                                               (before royalties)        (after royalties)
          <S>         <C>               <C>             <C>                    <C>                      <C>
            9           47,609           13,279               28%                  10.6 mmcf/d              8.2 mmcf/d
</TABLE>

During 1999, two wells on Block 604 (Chieftain 37%) were successfully
recompleted and at year-end were producing 2.2 mmcf/d, net to our working
interest. On Block 704 (Chieftain 25%), a 12,700 foot exploration well commenced
drilling during the fourth quarter of 1999. On Block 634 (Chieftain 24%) a 9,900
foot exploration well is expected to commence drilling by mid-2000.

HIGH ISLAND/EAST ADDITION/SOUTH EXTENSION:

<TABLE>

<CAPTION>
          Blocks      Gross Acres       Net Acres       Average Interest       Average Production        Average Production
          ------      -----------       ---------       ----------------       ------------------        ------------------
                                                                               (before royalties)         (after royalties)
          <S>         <C>               <C>             <C>                <C>                        <C>
           16           62,772           25,205               40%          10.0 mmcf/d and 81 bbls/d   8.2 mmcf/d and 66 bbls/d
</TABLE>

On Block 207 (Chieftain 50%), production increased significantly with a full
year's output from a well completed in 1998. During 1999 we sold our interest in
Block 134 (Chieftain 50%). On Block 206 (Chieftain 25%), acquired early in 2000,
a 12,000 foot exploration well commenced drilling in the first quarter.

HIGH ISLAND SOUTH ADDITION:

<TABLE>
<CAPTION>
          Blocks      Gross Acres       Net Acres       Average Interest       Average Production        Average Production
          ------      -----------       ---------       ----------------       ------------------        ------------------
                                                                               (before royalties)         (after royalties)
          <S>         <C>               <C>             <C>                    <C>                        <C>
           12           64,800           37,008              57%                   0.2 mmcf/d                0.1 mmcf/d
</TABLE>

Successful drilling was carried out on Blocks A-510/A-531 (Chieftain 50%) and
A-530 during 1999. For the 2000 year, additional exploratory and development
drilling is planned on Blocks A-510/A-531 and A-567. We operate High Island
A-510/A-531 where an 11,107 foot well encountered more than 260 feet of natural
gas and oil bearing pay in multiple zones. Design of production facilities, in a
water depth of 235 feet, is underway and production is scheduled to commence
late in 2000. At High Island A-530 (Chieftain 75%), a successful exploration
well encountered a total of 155 feet of natural gas pay in two zones. We also
operate this well, which is four miles southeast of the A-510/A-531 discovery. A
production facility is being designed for Block A-530 and initial production is
expected to commence during the fourth quarter of 2000.

     CENTRAL GULF (OFFSHORE LOUISIANA)

EAST CAMERON:

<TABLE>

<CAPTION>
          Blocks      Gross Acres       Net Acres       Average Interest       Average Production        Average Production
          ------      -----------       ---------       ----------------       ------------------        ------------------
                                                                               (before royalties)         (after royalties)
          <S>         <C>               <C>             <C>                <C>                        <C>
           12           51,479           15,660               30%          2.7 mmcf/d and 627 bbls/d   2.2 mmcf/d and 522 bbls/d
</TABLE>

The well on Block 34 (Chieftain 40%) was recompleted in the fourth quarter of
1999 and at year-end was producing 4.0 mmcf/d, net to our working interest. We
will act as operator and drill a 13,500 foot well on Block 255 (Chieftain 60%)
in the fourth quarter of 2000.

VERMILION:

<TABLE>

<CAPTION>
          Blocks      Gross Acres       Net Acres       Average Interest       Average Production        Average Production
          ------      -----------       ---------       ----------------       ------------------        ------------------
                                                                               (before royalties)         (after royalties)
          <S>         <C>               <C>             <C>                    <C>                        <C>
            4           10,806            3,447               32%                  1.5 mmcf/d                 1.1 mmcf/d
</TABLE>

During the fourth quarter of 1999, we participated in a natural gas discovery on
Block 267 (Chieftain 60%). Production facilities are being constructed and
initial production is scheduled to commence in the second quarter of 2000. When
facilities have been installed, two exploratory wells will be drilled from the
platform. Each of these wells will test a separate fault structure on the Block.
An exploratory well is also planned for Block 16 (Chieftain 14%) and a
development well is scheduled for Block 23 (Chieftain 25%).



                                                      3
<PAGE>   6

SOUTH MARSH ISLAND:

<TABLE>
<CAPTION>

Blocks     Gross Acres     Net Acres     Average Interest          Average Production              Average Production
------     -----------     ---------     ----------------          ------------------              ------------------
                                                                   (before royalties)              (after royalties)
<S>        <C>             <C>           <C>                       <C>                             <C>

  5           22,852         17,352            76%            4.9 mmcf/d and 1,250 bbls/d       4.1 mmcf/d and 1,041 bbls/d
</TABLE>


Production commenced from two wells on Block 39 (Chieftain 50%) during the
first quarter of 1999. Three successful wells, two exploratory and one
development, were drilled during the year and commenced production during the
third quarter. Further drilling in the South Marsh Island area is planned for
2000, including a development well on Block 39 (Chieftain 50%), a 13,500 foot
exploration well on Block 110 (Chieftain 50%) and an operated exploration well
on Block 138 (Chieftain 100%).

SOUTH TIMBALIER:

<TABLE>
<CAPTION>

Blocks     Gross Acres     Net Acres     Average Interest          Average Production              Average Production
------     -----------     ---------     ----------------          ------------------              ------------------
                                                                   (before royalties)              (after royalties)
<S>        <C>             <C>           <C>                       <C>                             <C>

  5           22,186         9,843             44%                        --                              --
</TABLE>

A 1999 discovery well on Block 196 (Chieftain 50%) encountered multiple natural
gas and oil sands. Platform installation and initial production is scheduled
for the second quarter of 2000. Additional exploratory drilling is planned for
Block 196 in 2000. We plan to drill a 10,000 foot exploratory well on Block 78
(Chieftain 50%) where we are operator.

WEST CAMERON:


<TABLE>
<CAPTION>

Blocks     Gross Acres     Net Acres     Average Interest          Average Production              Average Production
------     -----------     ---------     ----------------          ------------------              ------------------
                                                                   (before royalties)              (after royalties)
<S>        <C>             <C>           <C>                       <C>                             <C>

  10          43,934         16,421            37%                     1.6 mmcf/d                      1.4 mmcf/d
</TABLE>

During 1999 we participated in two natural gas discoveries in this area. On
Block 613 (Chieftain 25%), we participated in a multi-zone natural gas
discovery. Facilities design and construction is under way and first production
is expected to commence in mid-2000. Additional drilling on Block 613 is
scheduled to follow installation of the production facility. At West Cameron
300 (Chieftain 35%), an operated exploration well was drilled to 9,500 feet in
early 2000 and encountered two natural gas zones. A follow-up well is being
drilled. Facilities design for this project, in 40 feet of water, has commenced
and initial production is scheduled for late 2000. During the first half of
2000, we will participate, as operator, in the drilling of a 9,500 foot
exploration well on Block 386 (Chieftain 80%). In late 2000, a development well
will be drilled on producing Blocks 192/193 (Chieftain 25%).

MAIN PASS:


<TABLE>
<CAPTION>

Blocks     Gross Acres     Net Acres     Average Interest          Average Production              Average Production
------     -----------     ---------     ----------------          ------------------              ------------------
                                                                   (before royalties)              (after royalties)
<S>        <C>             <C>           <C>                       <C>                             <C>

  7           26,690         3,452             13%             18.0 mmcf/d and 206 bbls/d       13.8 mmcf/d and 155 bbls/d
</TABLE>

The Main Pass area is currently the most significant contributor to our natural
gas production. During 1999, development activity included drilling,
completions and facilities installation on Block 250 (Chieftain 20%) and Block
225 (Chieftain 10%), maintaining production at the prior year's levels.

     OTHER GULF OF MEXICO OPERATIONS:

Our 2000 drilling program for the Gulf of Mexico region includes approximately
27 wells, up from the 18 that were drilled in 1999. In addition to the wells
described above in our area analysis, the following wells are planned for 2000:
operated exploration wells at Brazos A-1 (Chieftain 100%), Eugene Island 355
(Chieftain 33%), Grand Isle 77 (Chieftain 67%) and Ship Shoal 257 (Chieftain
50%); non-operated exploration wells at Brazos 542 (Chieftain 6%) and Grand
Isle 103 (Chieftain 20%); and operated development wells at South Pass 37
(Chieftain 42%) and Eugene Island 189 (Chieftain 75%).


                                       4


<PAGE>   7
VERMILION PARISH, LOUISIANA

NORTHEAST WRIGHT:

<TABLE>
<CAPTION>
     Gross Acres    Net Acres      Average Interest    Average Production       Average Production
     -----------    ---------      ----------------    ------------------       ------------------
                                                       (before royalties)       (after royalties)
        <S>           <C>                <C>               <C>                      <C>
        3,688         1,841              50%               0.9 mmcf/d               0.7 mmcf/d
</TABLE>

In the Northeast Wright Field, the Broussard #1 well (Chieftain 50%) was
drilled to 18,400 feet to delineate and extend to the south the reserves
encountered by the 1998 D.W. Guidry #1 well. The Guidry well found 150 feet of
natural gas pay below 17,000 feet. The Broussard well found a significant
thickness of natural gas-bearing high quality reservoir sand. At year-end, the
Broussard well was tested and production commenced in January, 2000 at 8.5
mmcf/d (gross). We are participating in drilling the 19,000 foot Langlinais #1
well (Chieftain 50%), which commenced drilling northeast of the Broussard well
early in 2000. Our interest in the Guidry well is subject to a penalty on a
portion of the well costs. The extent of this reservoir could be revealed by
the 18,800 foot Delahoussaye #2 well (Chieftain 1.75%) which commenced drilling
at a location north of the field in February of 2000.

FOUR CORNERS (PARADOX BASIN) AREA, UTAH

ANETH UNIT:

<TABLE>
<CAPTION>
     Gross Acres    Net Acres        Unit Interest     Average Production       Average Production
     -----------    ---------      ----------------    ------------------       ------------------
                                                       (before royalties)       (after royalties)
          <S>          <C>                <C>                 <C>                      <C>
        18,070         3,066              13.4%           0.15 mmcf/d             0.13 mmcf/d
                                                         and 640 bbls/d          and 557 bbls/d
</TABLE>

RATHERFORD UNIT:

<TABLE>
<CAPTION>
     Gross Acres    Net Acres        Unit Interest     Average Production       Average Production
     -----------    ---------      ----------------    ------------------       ------------------
                                                       (before royalties)       (after royalties)
          <S>          <C>                <C>                 <C>                      <C>
        12,910         2,560              21.4%           0.45 mmcf/d              0.39 mmcf/d
                                                        and 1,386 bbls/d        and 1,213 bbls/d
</TABLE>

We have interests in two light oil fields where horizontal drilling has improved
the effectiveness of a waterflood enhanced recovery program being employed in
these fields. A pilot tertiary carbon dioxide recovery project in the Aneth
Field has shown favorable results and is continuing. A similar field-wide
project scheduled for 1999 in the Ratherford Unit was delayed due to low oil
prices. The Ratherford project is currently scheduled to proceed in late 2000.


NORTH SEA - UNITED KINGDOM SECTOR

<TABLE>
<CAPTION>
     Gross Acres    Net Acres       Unit  Interest     Average Production       Average Production
     -----------    ---------      ----------------    ------------------       ------------------
                                                       (before royalties)       (after royalties)
        <S>            <C>                <C>          <C>                        <C>
        60,273         9,644              16%             9.8 mmcf/d               9.8 mmcf/d
                                                        and 32 bbls/d             and 32 bbls/d
</TABLE>

All of our U.K. production comes from our interest in the Galahad Field
(Chieftain 17.8%). It is sold under 30-day contracts and in 1999 obtained an
average price of $0.96 per mcf, net of transportation costs. The U.K.
production is royalty free.

SIRTE BASIN, LIBYA

During 1999, it was concluded with our joint venture partners that an
exploration venture in Libya on a concession covering 3,888,550 (486,068 net)
acres in the Sirte Basin was not commercially viable and the holdings were
relinquished.

                                       5
<PAGE>   8
ACREAGE

The following table summarizes the developed and undeveloped acreage held by
Chieftain as at December 31, 1999. 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.......................    19,885           6,228         294,766      105,139
          Texas...........................    13,240           3,770         328,347      149,622
          Texas State.....................       300              22           4,872        1,468
                                             -------          ------         -------      -------
     Total Offshore Gulf of Mexico........    33,425          10,020         627,985      256,229
                                             =======          ======         =======      =======

     Onshore
          Louisiana.......................     2,110           1,055           4,400        2,197
          Montana.........................        --              --           3,240        3,240
          North Dakota....................       997             226           1,120          189
          Pennsylvania....................       324              36              --           --
          Utah............................    29,860           4,895           1,120          731
                                             -------          ------         -------      -------
     Total Onshore........................    33,291           6,212           9,880        6,357
                                             =======          ======         =======      =======
Total United States.......................    66,716          16,232         637,865      262,586
                                             =======          ======         =======      =======

United Kingdom

     North Sea............................     7,584           1,348          52,689        8,296
                                             =======          ======         =======      =======
Total, all areas..........................    74,300          17,580         690,554      270,882
                                             =======          ======         =======      =======
</TABLE>


Chieftain's developed and undeveloped acreage in all areas covered 764,854
(288,462 net) acres at December 31, 1999.

The undeveloped acreage, which has a cost to Chieftain of approximately $34
million, has not been independently evaluated.


GAS AND OIL CAPITAL EXPENDITURES

Reference is made to page 21 hereof for financial information with respect to
our net capital expenditures for the years ended December 31, 1999, 1998 and
1997.







                                       6



<PAGE>   9
DRILLING ACTIVITY

The following table summarizes the results of Chieftain's drilling activities
during the years ended December 31, 1999, 1998 and 1997.


<TABLE>
<CAPTION>

EXPLORATORY WELLS - Year ended December 31,

                                     1999                1998                1997
                                Gross     Net       Gross     Net       Gross     Net
                                -----     ---       -----     ---       -----    ----
<S>                             <C>      <C>        <C>      <C>        <C>      <C>
Gas ..........................    4      2.10         5      1.89         7      2.82

Oil ..........................   --        --         1      0.33        --        --

Oil/Gas ......................    4      2.00        --        --         1      0.50

Evaluating ...................    1      0.50        --        --        --        --

Drilling at end of year ......    3      0.62        --        --         3      0.94

Abandoned ....................    5      1.45         8      3.45         9      2.99
                                 --      ----        --      ----        --      ----
                                 17      6.67        14      5.67        20      7.25
                                 ==      ====        ==      ====        ==      ====
</TABLE>


<TABLE>
<CAPTION>
Development Wells - Year ended December 31,

                                     1999                1998                1997
                                Gross     Net       Gross     Net       Gross     Net
                                -----     ---       -----     ---       -----    ----
<S>                             <C>      <C>        <C>      <C>        <C>      <C>
Gas ..........................    5      0.77         4      0.32         9      1.77

Oil ..........................   --        --        30      6.01        34      6.15

Oil/Gas ......................    1      0.50         1      0.25        --        --

Evaluating ...................   --        --        --        --        --        --

Drilling at end of year ......   --        --        --        --         4      0.81

Abandoned ....................    1      0.50        --        --         1      0.50
                                 --      ----        --      ----        --      ----
                                  7      1.77        35      6.58        48      9.23
                                 ==      ====        ==      ====        ==      ====
</TABLE>

WELLS

Chieftain's productive gas and oil wells as at December 31, 1999 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 .........................   --        --       265     43.91

Louisiana ....................    2      1.00        --        --

U.S. Gulf of Mexico ..........   88     17.28        20      6.35

United Kingdom ...............    3      0.41        --        --
                                 --     -----       ---     -----
                                 98     19.62       287     50.73
                                 ==     =====       ===     =====
</TABLE>


RESERVES

Our U.S. natural gas and oil reserves have been evaluated by Netherland, Sewell
& Associates, Inc. ("NS&A") and we have evaluated our U.K. reserves which amount
to 2.2% (2.7% after royalties) of total equivalent reserves.

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


                                       7
<PAGE>   10
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, 1999, 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,                               1999           1998          1997
                                                    -------        -------       -------
<S>                                                 <C>            <C>           <C>
Total Net Production:

  Natural gas (mmcf)...........................      25,533         24,504        23,431
  Oil and liquids (mbbls)......................       1,428          1,100           825
  Gas equivalent (mmcfe).......................      34,103         31,102        28,383

Average Daily Net Production:

  Natural gas (mmcf)...........................        70.0           67.1          64.2
  Oil and liquids (bbls)*......................       3,913          3,012         2,261
  Gas equivalent (mmcfe).......................        93.4           85.2          77.8

Average Sales Price:

  Natural gas (per mcf)........................     $  2.02        $  1.99       $  2.33
  Oil and liquids (per bbl)....................     $ 17.05        $ 11.74       $ 18.94

Average Production Cost:

  Natural gas (per mcf)........................     $  0.21        $  0.30       $  0.27
  Oil and liquids (per bbl)....................     $  4.60        $  5.78       $  5.81
</TABLE>

* Oil comprised approximately 89% (1998 and 1997 - 82%) of the oil and liquids
  production.

EMPLOYEES

At December 31, 1999, Chieftain had 44 full-time equivalent employees. In
addition, Chieftain engages the services of consultants as required.

BUSINESS RISKS

If we cannot replace our reserves, our production and financial condition will
suffer.

Unless we successfully replace our reserves, our production will decline,
resulting in lower revenues and cash flow. Replacing our reserves is
particularly important because most of our reserves are in the U.S. Gulf of
Mexico where wells normally have steeper rates of decline than onshore wells.
Reduced reserves may also make borrowing and raising equity more difficult.
Furthermore, for the reasons discussed below, even if capital is spent on
drilling or to make acquisitions, such efforts have a risk of being
unsuccessful.

Drilling wells is speculative and capital intensive.

Exploring for oil and natural gas and developing oil and natural gas properties
require significant capital expenditures and involve a high degree of financial
risk. The budgeted costs of drilling, completing and operating wells are often
exceeded and can increase significantly when drilling costs rise and supply
tightens. Drilling may be unsuccessful for many reasons, including weather, cost
overruns, equipment shortages and mechanical difficulties. Moreover, the
successful drilling of an oil or natural gas well does not ensure a profit on
investment. Exploratory wells bear a much greater risk of loss than development
wells. A variety of factors, both geological and market-related, can cause a
well to become uneconomic or only marginally economic. In addition to their
costs, unsuccessful wells can hurt our efforts to replace reserves.

Reserves on properties we buy may not meet our expectations and could change the
nature of our business.

Property acquisition decisions are based on various assumptions and subjective
judgments that are speculative. Although available geological and geophysical
information can provide information about the potential of a property, it is
impossible to predict accurately a property's production and profitability.

                                       8
<PAGE>   11
In addition, we may have difficulty integrating future acquisitions into our
operations, and they may not achieve our desired profitability objectives.
Likewise, as is customary in the industry, we generally acquire oil and natural
gas acreage without any warranty of title except through the transferor. In some
instances, title opinions are not obtained if, in our judgment, it would be
uneconomical or impractical to do so. Losses may result from title defects or
from defects in the assignment of leasehold rights. While our current operations
are primarily in shallow waters of the U.S. Gulf of Mexico (offshore Texas and
Louisiana), we may pursue acquisitions or properties located in other geographic
areas, which would decrease our geographic concentration.

Estimates of our proved reserves are uncertain and our revenues from production
may vary significantly from estimated amounts.

The quantities and values of our proved reserves included in this Form 10-K are
only estimates and are subject to numerous uncertainties. Estimates by other
engineers might differ materially. The accuracy of any reserve estimate is a
function of the quality of available data and of engineering and geological
interpretation. These estimates depend on assumptions regarding quantities and
production rates of recoverable oil and natural gas reserves, future prices for
oil and natural gas, timing and amounts of development expenditures and
operating expenses, all of which will vary from those assumed in our estimates.
These variances may be significant.

Any significant variance from the assumptions used could result in the actual
amounts of oil and natural gas ultimately recovered and future net cash flows
being materially different from the estimates in our reserve reports. In
addition, results of drilling, testing, production and changes in prices after
the date of the estimate may result in substantial downward revisions. These
estimates may not accurately predict the present value of net cash flows from
oil and natural gas reserves.

At December 31, 1999, approximately 37% of our estimated proved reserves were
undeveloped. Recovery of undeveloped reserves generally requires additional
capital expenditures and successful drilling operations. The reserve data
assumes that we can and will make these expenditures and conduct these
operations successfully, which may not occur.

We do not insure against all potential losses and could be seriously harmed by
unexpected liabilities.

Exploration for and production of oil and natural gas can be hazardous,
involving natural disasters and other unforeseen occurrences such as blowouts,
cratering, fires and loss of well control, which can damage or destroy wells or
production facilities, injure or kill people, and damage property and the
environment. Because third party drilling contractors are used to drill our
wells, we may not realize the full benefit of worker's compensation laws in
dealing with their employees. We maintain insurance against many potential
losses and liabilities arising from our operations. However, in accordance with
customary industry practice, we may not be fully insured against these risks,
nor may all such risks be insurable.

Governmental regulations are costly and complex, especially regulations relating
to environmental protection.

Our U.S. exploration, production and marketing operations are regulated
extensively at the federal, state and local levels. These regulations affect the
costs, manner and feasibility of our operations. As an owner and operator of oil
and natural gas properties, we are subject to federal, state and local
regulation of discharge of materials into, and protection of, the environment.
We have made and will continue to make significant expenditures in our efforts
to comply with the requirements of these environmental regulations, which may
impose liability on us for the cost of pollution clean-up resulting from
operations, subject us to liability for pollution damage and require suspension
or cessation of operations in affected areas. Changes in, or additions to,
regulations regarding the protection of the environment could increase our
compliance costs and may negatively impact our business.

We are subject to state and local regulations that impose permitting,
reclamation, land use, conservation and other restrictions on our ability to
drill and produce. These laws and regulations can require well and facility
sites to be closed and reclaimed. We buy and sell interests in properties that
have been operated in the past, and, as a result of these transactions, we may
retain or assume clean-up or reclamation obligations for our own operations or
those of third parties.

U.S. offshore oil and natural gas operations are subject to regulations of the
United States Department of the Interior, which currently impose 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 damage. In the event of a serious incident of
pollution, a lessee under a federal lease may be required to suspend or cease
operations in the affected area.

In the U.K., deposits of substances or articles at sea from offshore oil and
natural 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.

                                       9
<PAGE>   12
We may have difficulty competing for oil and natural gas properties or supplies.

We operate in a highly competitive environment, competing with major integrated
and independent energy companies for desirable oil and natural gas properties,
as well as for the equipment, labor and materials required to develop and
operate those properties. Many of these competitors have financial resources
substantially greater than ours. We may incur higher costs or be unable to
acquire and develop desirable properties at costs we consider reasonable
because of this competition.



                                       10
<PAGE>   13
GLOSSARY

The following are defined terms used herein:

BBL means barrel (42 U.S. gallons).

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

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

BBLS/D means barrels per day.

BLOCK refers to an offshore U.S. 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 natural gas or
oil reservoir to the depth of a stratigraphic horizon known to be productive.

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

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

NATURAL GAS reserves are reported at a base pressure of 14.65 psia and a base
temperature of 60 degrees Fahrenheit.

NATURAL GAS EQUIVALENT is determined by using the approximate energy equivalent
ratio of 6 mcf of natural gas to 1 bbl 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.

MBBLS means 1,000 barrels.

MCF means 1,000 cubic feet.

MCF/D means 1,000 cubic feet per day.

MMCF means 1,000,000 cubic feet.

MMCF/D means 1,000,000 cubic feet per day.

MMCFE means 1,000,000 cubic feet of natural 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.

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 natural 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 natural 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
natural 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.



                                       11
<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

We are, in the ordinary course of business, party to various legal proceedings.
In the opinion of our management, none of these proceedings, either individually
or in the aggregate, is material.

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 1999.

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
25, 2000.

<TABLE>
<CAPTION>
Name                     Age       Position/Office
----                     ---       ---------------

<S>                      <C>       <C>
Stanley A. Milner        71        Director, President and Chief Executive Officer
Stephen C. Hurley        50        Director, Senior Vice President and Chief Operating Officer
James B. Lewis           50        Senior Vice President, Operations
Esther S. Ondrack        59        Director, Senior Vice President and Secretary
S. Jay Milner            42        Vice President, Drilling and Production
Ronald J. Stefure        52        Vice President and Controller
Randall P. Boyd          43        Vice President, Investor Relations
</TABLE>

With the following exceptions all of the officers have held positions as
officers of the Company since its incorporation in 1988, such position being his
or her principal occupation. S.C. Hurley joined Chieftain in September, 1995
prior to which time he was the Vice President, Exploration of a U.S. based
integrated oil company. J.B. Lewis joined Chieftain as a consultant in May 1998
and was appointed an officer of the Company in 1999. Prior to 1998, J.B.
Lewis was Vice President and General Manager, Offshore Division of a U.S. based
energy 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. R.P. Boyd joined Chieftain in 1999 prior to which time he was Chief
Financial Officer and Controller of a Canadian independent oil and gas 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.




                                       12
<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, 1997 are shown below.

<TABLE>
<CAPTION>
                                            Price History of Chieftain International, Inc. Common Shares
                                          American Stock Exchange                     Toronto Stock Exchange
                                                 (U.S. dollars)                            (Cdn. dollars)
                                              High            Low                       High            Low
     -------------------------------------------------------------------------------------------------------
<S>                              <C>                   <C>                        <C>            <C>
     1998
          First quarter                 $    24.75     $    17.94                 $    35.25     $    25.60
          Second quarter                     24.75          20.25                      35.35          30.10
          Third quarter                      23.75          13.94                      34.75          21.60
          Fourth quarter                     20.25          14.38                      30.70          22.75
     1999
          First quarter                      15.50           9.56                      24.00          14.50
          Second quarter                     18.63          12.25                      26.95          19.25
          Third quarter                      22.75          17.44                      34.00          25.90
          Fourth quarter                     20.38          14.06                      30.25          21.00

     2000
          January                            17.50          15.56                      25.00          22.50
          February                           17.75          13.38                      26.00          19.50
          March 1 to March 14                17.50          13.81                      25.50          20.35
</TABLE>


The Common Shares were held by 97 shareholders of record on December 31, 1999.
The Company estimates that investment dealers and other nominees hold Common
Shares for approximately 2,150 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. All dividends on the preferred
shares have been paid.



                                       13
<PAGE>   16
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA

The selected consolidated financial and operating data for each of the five
years ended December 31, 1999 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.

               SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA

                 CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARIES

<TABLE>
<CAPTION>

YEAR ENDED DECEMBER 31,                                    1999            1998            1997           1996           1995
                                                       ------------    ------------    ------------   ------------   ------------
                                                           (in thousands except shares, per share amounts and operating data)
<S>                                                    <C>             <C>             <C>            <C>            <C>
INCOME STATEMENT DATA:
Revenue ............................................   $     76,447    $     64,391    $     72,055   $     63,099   $     31,071
Production costs ...................................         14,320          16,355          13,325         12,220          9,563
General and administrative expenses ................          4,580           4,796           4,308          3,972          3,346
Interest ...........................................          2,496             437              --             --             --
Depletion and amortization(1) ......................         51,385          42,081          36,951         30,920         18,779
Additional depletion(2) ............................         16,186           6,244              --             --             --
Income (loss) from operations, before dividends
     on preferred shares of a subsidiary ...........         (6,897)         (4,113)         10,160          9,784           (775)
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) ..         (11,839)         (9,055)          5,218          4,842         (5,717)
Net income (loss) per common share(1) ..............          (0.86)          (0.67)           0.38           0.37          (0.54)
Weighted average number of common shares
     outstanding ...................................     13,701,419      13,480,067      13,620,728     13,065,414     10,633,142

OTHER DATA:
Cash flow from operations ..........................   $     50,098    $     37,847    $     49,473   $     41,841   $     13,186
Net natural gas and oil capital expenditures .......   $     55,021    $     92,573    $     69,453   $     57,673   $    100,502

BALANCE SHEET DATA (at end of period):
Working capital ....................................   $     13,604    $      2,392    $     22,676   $     42,854   $     11,216
Total assets(1) ....................................   $    330,758    $    318,584    $    285,125   $    267,442   $    204,555
Long-term debt .....................................   $     10,000    $     40,000    $         --   $         --   $         --
Shareholders' equity(1) ............................   $    271,101    $    234,946    $    249,466   $    244,122   $    190,534

OPERATING DATA:
Average Daily Net Production:
     Natural gas (mmcf) ............................           70.0            67.1            64.2           59.8           29.5
     Oil and liquids (bbls) ........................          3,913           3,012           2,261          2,005          1,643
     Natural gas equivalent (mmcfe) ................           93.4            85.2            77.8           71.8           39.3
Average Sales Price:
     Natural gas (per mcf) .........................   $       2.02    $       1.99    $       2.33   $       2.09   $       1.54
     Oil and liquids (per bbl) .....................          17.05           11.74           18.94          20.99          16.94
Average Production Cost:
     Natural gas (per mcf) .........................   $       0.21    $       0.30    $       0.27   $       0.25   $       0.35
     Oil and liquids (per bbl) .....................           4.60            5.78            5.81           6.57           7.31
</TABLE>


Notes:

     (1)  Reference is made to Note 12 of the Notes to Consolidated Financial
          Statements which describes the impact of United States accounting
          principles.

     (2)  This amount reflects write-downs in the carrying value of U.K. and
          Libyan gas and oil properties in 1999 and 1998 in accordance with full
          cost accounting rules under Canadian GAAP.

                                       14
<PAGE>   17
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
        OF OPERATIONS

You should read the following discussion and analysis in conjunction with our
1999 audited consolidated financial statements. The information contains
forward looking statements that are subject to risk factors associated with the
oil and gas business. We believe 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 and capital restrictions.

Our financial statements and information are reported in U.S. dollars and are
prepared based upon Canadian generally accepted accounting principles.
Substantially all of our revenues and a significant portion of our operating
expenses are realized or incurred in U.S. dollars. For a discussion of the
effect of differences in generally accepted accounting principles in Canada and
the U.S. on our financial statements, see Note 12 to our audited consolidated
financial statements. For purposes of calculating unit costs, oil and ngls are
converted to mcf equivalents using a conversion rate of one bbl of oil equal to
six thousand cubic feet of natural gas.

1999 OVERVIEW

We have achieved a three year record of 10% compounded annual production
growth. Production in 1999 averaged 112.9 mmcfe/d (93.4 mmcfe/d after
royalties) compared to 103.2 mmcfe/d (85.2 mmcfe/d after royalties) in 1998 and
93.4 mmcfe/d (77.8 mmcfe/d after royalties) in 1997. This growth has been
financed by cash flow, modest debt and equity.

Primarily as a result of higher production volumes and recovering commodity
prices, which resulted in increased net production revenues, cash flow from
operations, after preferred share dividends, was $50.1 million in 1999 compared
to $37.8 million in 1998 and $49.5 million in 1997.

Our average natural gas price was $2.02 per mcf in 1999 compared to $1.99 in
1998 and $2.33 in 1997. Our combined average crude oil and ngls price per bbl
was $17.05 in 1999 compared to $11.74 in 1998 and $18.94 in 1997.

Net capital spending was $55.1 million in 1999 compared to $92.7 million in
1998 and $69.8 million in 1997. Proved reserve finding and development costs in
1999 were $0.68 per mcfe ($0.84 per mcfe after royalties) compared to $1.54 per
mcfe ($2.04 per mcfe after royalties) in 1998 and $1.46 per mcfe ($1.80 per
mcfe after royalties) in 1997.

We increased our proved reserves for the sixth consecutive year, adding in
excess of 80 bcfe (65 bcfe after royalties), corresponding to a reserve
replacement rate of 197% (194% after royalties). Total proved reserves
increased to 290.3 bcfe (239.7 bcfe after royalties).

Our proved reserves at December 31, 1999 had a present value of future net cash
flows before income taxes, discounted at 10%, of $266.5 million (1998 - $152.5
million; 1997 - $238.3 million).

PRODUCTION

Our average daily combined natural gas and oil production increased nine
per cent to 112.9 mmcfe/d (93.4 mmcfe/d after royalties) in 1999 from 103.2
mmcfe/d (85.2 mmcfe/d after royalties) in 1998 and 93.4 mmcfe/d (77.8 mmcfe/d
after royalties) in 1997. Natural gas comprised 76% (75% after royalties) of our
production volume in 1999 compared to 80% (79% after royalties) in 1998 and 83%
(before and after royalties) in 1997. In 1999, natural gas production was 31.1
bcf (25.5 bcf after royalties) compared to 30.0 bcf (24.5 bcf after royalties)
in 1998 and 28.3 bcf (23.4 bcf after royalties) in 1997. In 1999, oil and
natural gas liquids production was 1,683 mbbls (1,428 mbbls after royalties)
compared to 1,271 mbbls (1,100 mbbls after royalties) in 1998 and 962 mbbls (825
mbbls after royalties) in 1997.

Eighty-eight per cent of 1999 natural gas production came from our interests in
111 wells in the U.S. Gulf of Mexico region compared to 89% (108 wells) in 1998
and 85% (100 wells) in 1997. In addition, 54% of our 1999 oil and ngls
production came from our interests in these wells (1998 - 28%; 1997 - 25%).

Comparing 1999 and 1998, a significant factor affecting increased production
volumes was the commencement of production at South Marsh Island 39 during the
first quarter of 1999. During 1999, South Marsh Island 39 contributed 1.8 bcf
(1.5 bcf after royalties) to our natural gas production and 456 mbbls (380
mbbls after royalties) to oil production. Initial production at Main Pass 225 D
and Main Pass 250 B contributed 0.3 bcf (0.2 bcf after royalties) and 1.0 bcf
(0.9 bcf after royalties), respectively, to 1999 natural gas production.
Contributing to increased annual production in 1999 was a full year of
production from both East Cameron 34 and High Island 207 B.


                                       15
<PAGE>   18
Comparing 1998 and 1997, the primary contributors to natural gas production
growth were East Cameron 349 and Main Pass 222/223. The Aneth and Ratherford
Units in the Four Corners area of Utah were the primary contributors to
increased oil production. East Cameron 349 commenced production in the fourth
quarter of 1997. In 1998 natural gas production from this field increased 0.9
bcf (0.8 bcf after royalties) to 1.3 bcf (1.1 bcf after royalties) and oil
production, though constrained by repairs to a third party pipeline during the
early part of the year, increased 148 mbbls (124 mbbls after royalties) to 184
mbbls (154 mbbls after royalties). Development drilling in 1998, combined with
increased transportation capacity via the Dauphin Island Gas Gathering System,
increased Main Pass 222/223 natural gas production by 2.7 bcf (2.0 bcf after
royalties) to 4.7 bcf (3.5 bcf after royalties). In 1998, we participated in 30
multi-lateral horizontal development wells in the Aneth and Ratherford Units in
addition to a tertiary carbon dioxide recovery pilot project in the Aneth Unit.
During 1998, combined oil and ngls production from these Units increased by 106
mbbls (93 mbbls after royalties) to 800 mbbls (699 mbbls after royalties).


PRODUCTION SUMMARY

<TABLE>
<CAPTION>
                                       Before royalties       After royalties
                                      -------------------   ------------------
                                       1999   1998   1997    1999  1998   1997
                                      -----  -----  -----   ----- -----  -----
<S>                                   <C>    <C>    <C>     <C>   <C>    <C>
Natural gas (mmcf/d)
  U.S.                                 75.5   73.8   66.6    60.2  58.6   53.2
  U.K.                                  9.8    8.5   11.0     9.8   8.5   11.0
                                      -----  -----  -----   ----- -----  -----
  Total                                85.3   82.3   77.6    70.0  67.1   64.2
                                      =====  =====  =====   ===== =====  =====
Oil and ngls (bbls/d)                 4,611  3,482  2,636   3,913 3,012  2,261
                                      =====  =====  =====   ===== =====  =====
Total natural gas equivalent
  (mmcfe/d)                           112.9  103.2   93.4    93.4  85.2   77.8
                                      =====  =====  =====   ===== =====  =====
Total annual equivalent
  (bcfe)                               41.2   37.7   34.1    34.1  31.1   28.4
                                      =====  =====  =====   ===== =====  =====
</TABLE>

GAS AND OIL MARKETING

Most of our natural gas reserves are located in the U.S. Gulf of Mexico region
where ready deliverability through numerous large capacity pipelines and
auxiliary feeder pipelines provides flexibility in marketing our production in
the U.S. spot market. Natural gas prices in the U.S. and in the U.K. are largely
determined by competitive market forces.

Most of the natural gas produced by us has been marketed since 1989 by Highland
Energy Company, an aggregator for several U.S. natural gas producers.

We have sold our oil production from the Aneth and Ratherford Units in the Four
Corners area of Utah under successive term contracts to a regional refiner since
1989. Due to the quantity and quality of this oil, we have obtained premiums
over locally posted prices for this production. Most of our U.S. Gulf of Mexico
oil and natural gas liquids production is marketed by Highland Energy Company.

Market prices of oil and natural gas fluctuate and can adversely affect our
operating results. We sell most of our natural gas under short term contractual
arrangements and do not engage in speculative forward selling of volumes that
cannot be physically delivered. To mitigate some of this risk, from time to time
we may enter into forward contracts for a portion of our production so as to
lock in a firm natural gas price for a specific volume and delivery period.

At December 31, 1999, we had entered into natural gas forward contracts through
Highland Energy Company and an oil forward contract with the regional refiner.
The forward contracts, all of which are for 2000 production, are for the
physical delivery of natural gas volumes totaling 6.1 bcf (approximately 15% to
20% of our forecast 2000 volume), at an average price, net of transportation, of
$2.49 per mcf, and for the physical delivery of 90 mbbls (approximately 5% of
our forecast 2000 volume) of oil, at an average price of $19.00 per bbl. Forward
contract volumes at both December 31, 1998 and 1997 were immaterial.

NATURAL GAS

Our composite average natural gas price was $2.02 per mcf in 1999 compared to
$1.99 in 1998 and $2.33 in 1997. The mild North American winter of 1998-1999 had
a significant downward effect on 1998 U.S. natural gas prices, which were 33%
lower in the fourth quarter than in the corresponding period in 1997. Natural
gas prices in the U.S. continued to be extremely weak during the first quarter
of 1999, when we received an average of $1.54 per mcf. Thereafter, prices
increased to an average of $2.39 per mcf in the fourth quarter of 1999. For the
full 1999 year, our average U.S. natural gas price was $2.16 per mcf
(1998-$2.06; 1997-$2.47) and our average U.K. natural gas price was $0.96 per
mcf (1998-$1.40; 1997-$1.49).

                                       16

<PAGE>   19
OIL AND NGLS

Our combined average oil and ngls price per bbl was $17.05 in 1999 compared to
$11.74 in 1998 and $18.94 in 1997. In 1998, the combination of economic
problems in Asia, the mild North American winter and aggressive international
competition for market share caused oil prices to fall sharply. Oil prices
continued to be extremely weak during the first quarter of 1999. We received an
average of $10.94 per bbl during the first quarter of 1999 and the recovery in
prices resulted in an average of $21.67 per bbl during the fourth quarter of
1999.

REVENUE

The 1999 growth in our combined natural gas and oil production volumes was
complemented by the recovery in commodity prices. As a result, 1999 production
revenue increased 22% from 1998 to $91.5 million ($75.4 million after
royalties). In 1998, growth in our combined natural gas and oil production
volumes was more than offset by decreases in natural gas and oil prices. As a
result, 1998 production revenues decreased 11% from 1997 to $74.9 million
($61.6 million after royalties).

INTEREST AND OTHER REVENUE

Interest and other revenue in 1998 included 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.

NET REVENUE

<TABLE>
<CAPTION>
                                                                        1999      1998       1997
---------------------------------------------------------------------------------------------------
                                                                            (in thousands)
<S>                                                                   <C>       <C>        <C>
Natural gas, after royalties                                          $50,765   $48,501    $ 53,937
Oil and ngls, after royalties                                          24,601    13,114      15,690
                                                                      -------   -------    --------
Production revenue, after royalties                                    75,366    61,615      69,627
Interest and other revenue                                              1,081     2,776       2,428
                                                                      -------   -------    --------
Total net revenue                                                     $76,447   $64,391    $ 72,055
                                                                      =======   =======    ========
</TABLE>

PRICE/VOLUME VARIANCES

<TABLE>
<CAPTION>


                                                          Natural gas
                                                  ---------------------------     Oil
                                                    U.S.      U.K.     Total    and ngls    Total
---------------------------------------------------------------------------------------------------
                                                                 (in thousands)
<S>                                               <C>       <C>       <C>       <C>        <C>
1997 production revenue, after royalties          $47,946   $ 5,991   $53,937   $15,690    $ 69,627
                                                  -------   -------   -------   -------    --------
  Price variance                                   (8,706)     (277)   (8,983)   (7,773)    (16,756)
  Volume variance                                   4,925    (1,378)    3,547     5,197       8,744
                                                  -------   -------   -------   -------    --------
1998 production revenue, after royalties           44,165     4,336    48,501    13,114      61,615
                                                  -------   -------   -------   -------    --------
  Price variance                                    2,064    (1,597)      467     7,626       8,093
  Volume variance                                   1,102       695     1,797     3,861       5,658
                                                  -------   -------   -------   -------    --------
1999 production revenue, after royalties          $47,331   $ 3,434   $50,765   $24,601    $ 75,366
                                                  =======   =======   =======   =======    ========
</TABLE>

EXPENSES

ROYALTIES

Royalties include payments made to federal and state governments, freehold
land owners and other third parties. Our U.S. Gulf of Mexico properties in U.S.
federal waters generally carry a one-sixth (16-2/3%) royalty rate. Some of
these offshore properties carry overriding royalties ranging from 1.1% to 10%.
In 1999, the effective overriding royalty rate was 2.2% (1998-2.7%; 1997-2.7%).

Production from the Aneth and Ratherford Units is subject to a 12.5% royalty.
The Aneth unit carries an additional royalty burden of approximately 2%. The
Northeast Wright field, in Louisiana, is subject to a royalty rate of 26%.

The U.K. properties carry no royalty obligations. As the U.K. properties
mature, natural production declines will reduce the proportion of this
production in our mix and our composite royalty per mcfe can be expected to
increase.

We pay no overriding royalties to management or staff.


                                       17

<PAGE>   20
       ROYALTIES

<TABLE>
<CAPTION>

                                                         1999            1998       1997
       -----------------------------------------------------------------------------------
                                                          (in thousands except per unit
                                                             amounts and percentages)
       <S>                                             <C>            <C>         <C>
       Natural gas                                     $ 11,699       $ 11,211    $ 12,007
       Oil and ngls                                       4,442          2,035       2,585
                                                       --------       --------    --------
       Total                                           $ 16,141       $ 13,246    $ 14,592
                                                       ========       ========    ========
       Royalties ($/mcfe)                                 $0.39          $0.35       $0.43
       Composite royalty rate                              17.6%          17.7%       17.3%
</TABLE>


PRODUCTION COSTS

Our production costs in 1999 decreased 12% from 1998, a result of non-recurring
significant items in 1998 and the termination of the Libyan production test.
Our production costs in 1998 increased 23% from 1997 primarily as a result of
several weather-induced evacuations of manned facilities in the U.S. Gulf of
Mexico during the third quarter of 1998 and significant pipeline repair costs
in the South Pass area.

Production costs for U.S. Gulf of Mexico region properties were $0.25 per mcfe
($0.31 per mcfe after royalties) in 1999 compared to $0.32 per mcfe ($0.41 per
mcfe after royalties) in 1998 and $0.30 per mcfe ($0.37 per mcfe after
royalties) in 1997. Production costs for the Aneth and Ratherford Units, which
are primarily oil producing properties where secondary and tertiary recovery
methods are being used, were $1.15 per mcfe ($1.32 per mcfe after royalties) in
1999 compared to $0.99 per mcfe ($1.13 per mcfe after royalties) in 1998 and
$1.06 per mcfe ($1.21 per mcfe after royalties) in 1997.



       PRODUCTION COSTS

<TABLE>
<CAPTION>
                                                         1999           1998        1997
       -------------------------------------------------------------------------------------
                                                      (in thousands except per unit amounts)
       <S>                                             <C>             <C>        <C>
       Lifting costs                                   $ 12,929         $14,899   $ 11,569
       Production taxes                                   1,391           1,456      1,756
                                                       --------        --------    -------
       Production costs                                $ 14,320        $ 16,355   $ 13,325
                                                       ========        ========   ========
       Production costs ($/mcfe)
         Before royalty volumes                           $0.35           $0.43      $0.39
         After royalty volumes                            $0.42           $0.53      $0.47
</TABLE>

Production from the Aneth and Ratherford Units and the Northeast Wright Field
in Louisiana is subject to production and severance taxes. As a result of the
price dependent methodologies used to calculate these taxes, and the
anticipated additional production from the Broussard #1 well in the Northeast
Wright Field, we expect that our production taxes will nearly double in 2000.

GENERAL AND ADMINISTRATIVE

Our general and administrative costs decreased 5% in 1999 compared to 1998 and
increased 11% for 1998 compared to 1997. Performance-based compensation
payments were lower in 1999 than in 1998 and higher in 1998 than in 1997.


       GENERAL AND ADMINISTRATIVE
<TABLE>
<CAPTION>
                                                         1999            1998         1997
       --------------------------------------------------------------------------------------
                                                          (in thousands except per unit
                                                             amounts and percentages)
       <S>                                             <C>             <C>          <C>
       Gross general and administrative                $ 8,527         $ 9,108      $ 7,859
       Capitalized                                      (3,947)         (4,312)      (3,551)
                                                       --------        --------      -----
       General and administrative expense              $ 4,580         $ 4,796      $ 4,308
                                                       ========        ========     =======
       General and administrative ($/mcfe)
         Before royalty volumes                          $0.11           $0.13        $0.13
         After royalty volumes                           $0.13           $0.15        $0.15
       Capitalization ratio                                 46%             47%          45%

</TABLE>



INTEREST

Interest expense increased to $2.5 million in 1999 compared to $0.4 million in
1998 due to greater credit facility utilization. Our weighted average debt
outstanding during 1999 was $42.1 million compared to $12.3 million in 1998.
The effective interest rate on our outstanding debt for 1999 was 5.93% compared
to 6.19% in 1998. The interest rate on our debt at December 31, 1999 was 7.00%.




                                      18
<PAGE>   21

DEPLETION AND AMORTIZATION

Depletion and amortization expense in 1999 increased 22% compared to 1998 as a
result of a 9% increase in production and a 12% increase in the average
depletion rate. The downward revision in our proved reserves at December 31,
1998 that resulted from low oil prices at that date contributed to the increase
in our effective depletion rate. Comparing 1998 and 1997, depletion and
amortization expense increased 14%, the result of an 11% increase in units of
production and a 4% increase in the average depletion rate.

Accounting rules require that we review regularly, on a country-by-country
basis, the carrying value of our oil and gas properties for possible write-down
or impairment. Under these rules, capitalized costs of proved reserves may not
exceed the value of estimated future net revenues from those proved reserves.
Full cost accounting rules allow, but do not require, companies to exclude costs
of acquiring and evaluating unproved properties from their depletion cost
centres, but if such costs are excluded, they must be separately assessed for
impairment. Our policy on depletion does not exclude such costs from their
respective depletion cost centres. The scope of our Libyan venture was such that
we did not apply this policy. Libyan costs were excluded and separately assessed
for impairment.

In Libya, we and our partners concluded that the multi-year exploration program,
and the production test which commenced in December 1997, were not commercial
under the terms of the concession and therefore terminated the venture. As a
result, additional depletion of $11.4 million was recorded in the second quarter
of 1999 to eliminate the investment. An impairment provision of $5.1 million was
recorded at December 31, 1998 in respect of one of the Libyan concessions upon
which no further exploration had been planned.

In the U.K. we recorded ceiling test impairments due to very low spot market
prices for natural gas at December 31, 1999, and downward reserve revisions at
December 31, 1998.

TAXES

We have $224.5 million in U.S. tax pools and $34.8 million in Canadian tax pools
to reduce future taxable income. The only current income taxes expected for the
next several years are Canadian federal taxes on capital, the amounts of which
are currently expected to remain comparable with 1999 and 1998.

NETBACK

<TABLE>
<CAPTION>
          NETBACK ANALYSIS ($/mcfe)                        Before royalties              After royalties
                                                       ------------------------      ------------------------
                                                       1999      1998      1997      1999      1998      1997
                                                      -----     -----     -----     -----     -----     -----
<S>                                                  <C>       <C>       <C>       <C>       <C>       <C>
          Gross production revenue                   $ 2.22    $ 1.99    $ 2.47
            Royalties                                 (0.39)    (0.35)    (0.43)
                                                     ------    ------    ------
          Production revenue, after royalties          1.83      1.64      2.04    $ 2.21    $ 1.98    $ 2.45
            Production costs                          (0.35)    (0.43)    (0.39)    (0.42)    (0.53)    (0.47)
                                                     ------    ------    ------    ------    ------    ------
          Gross margin                                 1.48      1.21      1.65      1.79      1.45      1.98
            General and administrative expenses       (0.11)    (0.13)    (0.13)    (0.13)    (0.15)    (0.15)
                                                     ------    ------    ------    ------    ------    ------
          Gross profit                                 1.37      1.08      1.52      1.66      1.30      1.83
            Interest and other                        (0.03)     0.05      0.07     (0.04)     0.08      0.08
            Preferred share dividends                 (0.12)    (0.13)    (0.14)    (0.15)    (0.16)    (0.17)
                                                     ------    ------    ------    ------    ------    ------
          Cash flow from operations                  $ 1.22    $ 1.00    $ 1.45    $ 1.47    $ 1.22    $ 1.74
                                                     ======    ======    ======    ======    ======    ======
          Annual production volume (bcfe)              41.2      37.7      34.1      34.1      31.1      28.4
                                                     ======    ======    ======    ======    ======    ======
</TABLE>



                                       19
<PAGE>   22
CAPITAL EXPENDITURES

Natural resource capital expenditures were $55.0 million in 1999, compared to
$92.6 million in 1998 and $69.5 million in 1997.

DRILLING RESULTS

In 1999, our exploratory drilling success rate in the U.S. Gulf of Mexico region
was 73% compared to 43% in 1998 and 47% in 1997. Including development wells,
our success rate in the region was 78% in 1999 compared to 58% in 1998 and 63%
in 1997. Drilling in all areas, including extensive development drilling in the
Utah oil producing units in 1998 and 1997, resulted in success rates of 70% in
1999 and 84% in both 1998 and 1997.

<TABLE>
<CAPTION>
DRILLING RESULTS (WELLS)              1999            1998            1997
                                 -------------   -------------   -------------
                                 GROSS    NET    GROSS    NET    GROSS    NET
                                 -----   -----   -----   -----   -----   -----
<S>                              <C>     <C>     <C>     <C>     <C>     <C>
U.S. - Gulf of Mexico region
   Successful                       14    5.37      11    2.79      17    5.09
   Dry                               4    1.70       8    3.45      10    3.49
                                 -----   -----   -----   -----   -----   -----
                                    18    7.07      19    6.24      27    8.58
                                 -----   -----   -----   -----   -----   -----

U.S. - Other
   Successful                       --      --      30    6.01      34    6.15
   Dry                              --      --      --      --      --      --
                                 -----   -----   -----   -----   -----   -----
                                    --      --      30    6.01      34    6.15
                                 -----   -----   -----   -----   -----   -----

Total U.S.
   Successful                       14    5.37      41    8.80      51   11.24
   Dry                               4    1.70       8    3.45      10    3.49
                                 -----   -----   -----   -----   -----   -----
                                    18    7.07      49   12.25      61   14.73
                                 -----   -----   -----   -----   -----   -----

Foreign
   Dry                               2    0.25      --      --      --      --
                                 -----   -----   -----   -----   -----   -----

Total drilling
   Successful                       14    5.37      41    8.80      51   11.24
   Dry                               6    1.95       8    3.45      10    3.49
                                 -----   -----   -----   -----   -----   -----
                                    20    7.32      49   12.25      61   14.73
                                 =====   =====   =====   =====   =====   =====
Chieftain operated wells             5    2.75       2    2.00       2    1.67
                                 =====   =====   =====   =====   =====   =====
</TABLE>




In addition to the wells described above, at December 31, 1999 we had interests
in three (0.62 net) wells which were drilling and one (0.50 net) well which was
being evaluated. No wells were drilling or being evaluated at December 31, 1998;
seven (1.75 net) wells were drilling at December 31, 1997.

Five additional wells were drilled in 1999 on our U.S. Gulf of Mexico region
acreage at no cost to us, one of which resulted in a natural gas well and four
of which were unsuccessful. In 1998, one successful natural gas well was drilled
on our U.S. Gulf of Mexico region acreage at no cost to us. There was no
corresponding activity in 1997.

CAPITAL FIELD DEVELOPMENT ACTIVITY

Our principal development activity in 1999 was at South Marsh Island 39 where
two satellite platforms, a host platform and associated pipelines were
installed. Installation of production facilities at Main Pass 225 D and Main
Pass 250 B were the other significant development activities during the year.


                                       20

<PAGE>   23

<TABLE>
<CAPTION>
CAPITAL EXPENDITURES SUMMARY
                                                         1999      1998     1997
                                                       -------   -------  -------
                                                              (in thousands)

<S>                                                    <C>       <C>      <C>
Property acquisition costs:
     U.S.                                              $ 5,352   $ 7,903  $ 9,164
     U.K.                                                   28       115      137
                                                       -------   -------  -------
                                                         5,380     8,018    9,301
                                                       -------   -------  -------

Sale of producing properties:
     U.S.                                                 (155)       --       --
                                                       -------   -------  -------

Purchase of producing properties:
     U.S.                                                   --       883       --
                                                       -------   -------  -------

Exploration costs:
     U.S.                                               28,753    43,317   35,540
     U.K.                                                    9        72      115
     Other foreign                                       1,531       606    1,207
                                                       -------   -------  -------
                                                        30,293    43,995   36,862
                                                       -------   -------  -------

Development costs:
     U.S.                                               19,542    39,606   23,260
     U.K.                                                  (39)       71       30
                                                       -------   -------  -------
                                                        19,503    39,677   23,290
                                                       -------   -------  -------
                                                       $55,021   $92,573  $69,453
                                                       =======   =======  =======
</TABLE>

FINDING AND DEVELOPMENT COSTS

COST OF RESERVE ADDITIONS

For 1999, finding and development costs were $0.68 per mcfe ($0.84 after
royalties) based on proved reserves added.

In calculating finding costs, a number of anomalies between periods are created
by the timing of expenditures and the phase of the exploration cycle. This
relates particularly to lease acquisitions and to major facility construction,
as well as to recognition and revision of reserves. Multi-year cumulative
average calculations are a more meaningful reflection of a company's ability to
find and produce reserves effectively. We have included both a three-year
calculation and one year components in the following table.

<TABLE>
<CAPTION>
FINDING COST ANALYSIS
                                                                        Cumulative
                                   1999        1998        1997          1997-1999
                                   ----        ----        ----          ---------
                                   (in thousands except unit and per unit amounts)
<S>                                <C>         <C>         <C>          <C>
Capital expenditures             $55,021     $ 92,573    $ 69,453        $ 217,047
                                 =======     ========    ========        =========
Proved, before royalties
     Reserve additions (mmcfe)    80,898       59,999      47,469          188,366
     Finding costs ($/mcfe)      $  0.68     $   1.54    $   1.46        $    1.15
Proved, after royalties
     Reserve additions (mmcfe)    65,796       45,381      38,668          149,845
     Finding costs ($/mcfe)      $  0.84     $   2.04    $   1.80        $    1.45
</TABLE>

RESERVE REPLACEMENT

For the sixth consecutive year, we added more proved reserves than we produced,
on an annual all sources basis, with total proved reserves increasing to 290.3
bcfe (239.7 bcfe after royalties).

The success of our strategy of growth through exploration is demonstrated by
the increase in reserves replaced through drilling. Ninety-five per cent (94%
after royalties) of our increase in proved U.S. reserves in 1999 resulted from
extensions, discoveries and other additions, compared to 90% (93% after
royalties) in 1998 and 69% (70% after royalties) in 1997.

                                       21
<PAGE>   24
RESERVES

Reports prepared by Netherland, Sewell & Associates, Inc., independent petroleum
engineers, as to our U.S. reserves and by ourselves as to our U.K. reserves,
contain estimates of our total proved reserves, before and after royalty
deductions, as described below. U.K. reserves comprise 2.2% (2.7% after
royalties) of our total proved reserves on a bcfe basis.

     RESERVE RECONCILIATION

<TABLE>
<CAPTION>

                                                             Before royalties                    After royalties
                                                      -------------------------------   ----------------------------------
                                                      Natural gas        Oil and ngls       Natural gas       Oil and ngls
                                                        (mmcf)             (mbbls)            (mmcf)             (mbbls)
                                                       --------           --------           --------           --------
<S>                                                    <C>                 <C>               <C>                 <C>
December 31, 1997                                       149,443             13,006            125,097             11,313
                                                       --------           --------           --------           --------
  Purchase of producing properties                        4,745                 18              3,512                 14
  Revision of previous estimates                          5,564             (1,502)             2,700             (1,339)
  Extensions, discoveries and other additions            29,360              4,872             22,268              4,142
  Sale of proved properties                                  --                 --                 --                 --
                                                       --------           --------           --------           --------
  Net additions                                          39,669              3,388             28,480              2,817
  Production                                            (30,048)            (1,167)           (24,504)              (996)
                                                       --------           --------           --------           --------
December 31, 1998                                       159,064             15,227            129,073             13,134
                                                       --------           --------           --------           --------
  Purchase of producing properties                           --                 --                 --                 --
  Revision of previous estimates                         (5,786)             1,607             (4,858)             1,480
  Extensions, discoveries and other additions            64,127              2,152             51,251              1,753
  Sale of proved properties                                  --                 --                 --                 --
                                                       --------           --------           --------           --------
  Net additions                                          58,341              3,759             46,393              3,233
  Production                                            (31,119)            (1,656)           (25,533)            (1,401)
                                                       --------           --------           --------           --------
December 31, 1999                                       186,286             17,330            149,933             14,966
                                                       ========           ========           ========           ========

</TABLE>

PROVED RESERVE LIFE INDEX (years)

<TABLE>
<CAPTION>
                                                           Before royalties                        After royalties
                                                     -----------------------------------       -----------------------------
                                                       1999         1998         1997         1999         1998         1997
                                                     --------     -------      ---------    --------     -------     -------
<S>                                                     <C>          <C>          <C>          <C>          <C>          <C>
  Natural gas                                           6.0          5.3          5.3          5.9          5.3          5.3
  Oil and ngls                                         10.5         13.0         13.7         10.7         13.2         13.9
  Equivalent                                            7.1          6.8          6.7          7.1          6.8          6.8
</TABLE>


Reserve life indexes are the quotients of year end reserve volumes divided by
the year then ended's associated production volumes.

RESERVES SUMMARY - NATURAL GAS (mmcf)

<TABLE>
<CAPTION>
                                              Before royalties                        After royalties
                                   ------------------------------------   ------------------------------------
                                        1999         1998         1997        1999         1998          1997
                                   ----------   ----------   ----------   ----------   ----------   ----------
<S>                                    <C>          <C>          <C>          <C>          <C>          <C>
Proved reserves:

  Developed producing - U.S.           63,822       70,082       55,013       50,531       55,418       43,979
                      - U.K.            6,376       10,108       18,317        6,376       10,108       18,317
  Developed non-producing - U.S.       58,986       41,974       32,660       46,024       33,906       26,843
  Undeveloped - U.S.                   57,102       36,900       43,453       47,002       29,641       35,958
                                   ----------   ----------   ----------   ----------   ----------   ----------
Total proved reserves                 186,286      159,064      149,443      149,933      129,073      125,097
                                   ==========   ==========   ==========   ==========   ==========   ==========
</TABLE>

RESERVES SUMMARY - OIL AND NGLs (mbbls)

<TABLE>
<CAPTION>
                                              Before royalties                       After royalties
                                    ------------------------------------   ------------------------------------
                                       1999         1998         1997        1999         1998          1997
----------------------------------  ----------   ----------   ----------   ----------   ----------   ----------
<S>                                    <C>          <C>          <C>          <C>          <C>          <C>
Proved reserves:
    Developed producing - U.S.           7,447        5,430        8,209        6,580        4,739        7,241
                        - U.K.              20           27           59           20           27           59
    Developed non-producing - U.S.       1,633        3,329        1,323        1,347        2,768        1,097
    Undeveloped - U.S.                   8,230        6,441        3,415        7,019        5,600        2,916
                                    ----------   ----------   ----------   ----------   ----------   ----------
  Total proved reserves                 17,330       15,227       13,006       14,966       13,134       11,313
                                    ==========   ==========   ==========   ==========   ==========   ==========
</TABLE>

                                       22

<PAGE>   25

NET FUTURE CAPITAL EXPENDITURES

The reserve reports incorporate future capital expenditures, spanning a period
of approximately 24 years (1998-20 years; 1997-20 years), required to bring
proved undeveloped reserves to production, to maintain proved producing
reserves, and to provide for future abandonment.


<TABLE>
<CAPTION>
    NET FUTURE CAPITAL EXPENDITURES
                                                                                                    1999         1998         1997
    --------------------------------------------------------------------------------------------------------------------------------
                                                                                                            (in thousands)
<S>                                                                                               <C>          <C>          <C>
    Proved developed                                                                              $ 28,120     $ 29,131     $ 24,004
    Proved undeveloped                                                                              56,753       32,532       34,655
                                                                                                  --------     --------     --------

    Total                                                                                         $ 84,873     $ 61,663     $ 58,659
                                                                                                  ========     ========     ========
</TABLE>

RESERVE VALUE RECONCILIATION

The present value of our reserves, discounted at 10% and using constant natural
gas and oil prices in effect on the balance sheet date, increased 47% to $224.5
million at December 31, 1999 compared $152.5 million at December 31, 1998 and
$199.6 million at December 31, 1997.

Our reserves are estimated using year-end prices which, at December 31, 1999,
were $20.40 per bbl for oil and $2.51 per mcf for U.S. natural gas. The use of
year end prices imposes a stringent economic limit on estimates of reserves
recoverable in the future. If escalating prices were applied, greater volumes of
reserves would be recoverable.

<TABLE>
<CAPTION>
    ESTIMATED PRESENT VALUE OF PROVED RESERVES
                                                                                                   1999         1998         1997
    -------------------------------------------------------------------------------------------------------------------------------
                                                                                                          (in thousands)
<S>                                                                                              <C>          <C>          <C>
    Proved developed                                                                             $193,935     $135,867     $187,697
    Proved undeveloped                                                                             72,539       16,641       50,615
                                                                                                 --------     --------     --------
    Total PV-10 value before income taxes                                                        $266,474     $152,508     $238,312
                                                                                                 ========     ========     ========
    Standardized measure of discounted estimated future net cash flows after income taxes        $224,533     $152,508     $199,573
                                                                                                 ========     ========     ========
</TABLE>

<TABLE>
<CAPTION>
    PRICES USED IN CALCULATING PROVED RESERVES
                                                                                                   1999       1998       1997
    ------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                               <C>        <C>        <C>
    Natural gas (per mcf)
        U.S.                                                                                      $ 2.51     $ 2.15     $ 2.74
        U.K.                                                                                      $ 0.99     $ 1.74     $ 1.76
    Oil and ngls (per bbl)                                                                        $20.40     $ 9.72     $16.69
</TABLE>

CAPITAL RESOURCES AND LIQUIDITY

Our primary sources of cash are funds generated from operations and financing
activities. Our primary cash outflows are for exploration and development
activities.

Discretionary cash flow, a frequently used measure of performance for
exploration and production companies, is derived by adjusting net income (loss)
attributable to common shares to eliminate the effects of depletion and
amortization, additional depletion and deferred income taxes. We generated
discretionary cash flow of $50.1 million in 1999 compared to $37.8 million in
1998 and $49.5 million in 1997. The variances are primarily a function of
fluctuating revenues caused by the volatility of commodity prices.

Our financing activities in 1999 provided $16.2 million of cash, the net result
of:

o    the sale of 2,875,000 common shares for $46.3 million net of issue costs;

o    the net repayment of $30 million of our revolving credit facility, which
     increased the unutilized portion to $90 million; and

o    the purchase for cancellation of 7,500 common shares at the cost of $0.1
     million under our share repurchase program, which expired on November 1,
     1999.


                                       23


<PAGE>   26
Financing activities during 1998 provided $34.5 million of cash, the net result
of:

o   the drawdown of $40 million of our revolving credit facility;

o   the exercise of employee share options for $0.4 million; and

o   the purchase for cancellation of 294,700 common shares at the cost of $5.9
    million under our share repurchase program.

Financing activities during 1997 provided $0.1 million of cash, which was the
net result of:

o   the exercise of employee share options for $1.0 million; and

o   the purchase for cancellation of 36,300 common shares at the cost of $0.9
    million under our share repurchase program.

Cash used in natural resource investing activities decreased to $55.0 million
for 1999 compared to $92.6 million and $69.5 million for 1998 and 1997,
respectively. The composition of our natural resource investing activities is
as follows:

<TABLE>
<CAPTION>
                COMPOSITION OF NATURAL RESOURCE INVESTING ACTIVITIES

                                                              1999     1998        1997
                                                            -------   -------    -------
                                                                   (in thousands)
               <S>                                          <C>       <C>        <C>
               Leasehold and seismic                        $ 7,854   $10,757    $15,451
               Purchase (sale) of producing properties         (155)      883         --
               Exploratory drilling                          27,819    41,256     30,712
               Development drilling                           9,775    16,517     15,178
               Capital field development                      9,728    23,160      8,112
                                                            -------   -------    -------
               Total                                        $55,021   $92,573    $69,453
                                                            =======   =======    =======
</TABLE>

Our December 31, 1999 cash balance of $19.4 million was up $8.8 million from
1998, which, in turn, was down $16.3 million from 1997. We had outstanding
borrowings of $10 million on our $100 million revolving credit facility at
December 31, 1999 (1998 - $40 million; 1997 - $nil). The weighted average
interest rate on our borrowings for 1999 was 5.93% (1998 - 6.19%).

RISK ASSESSMENT

There are a number of risks facing participants in the oil and gas industry.
Some of the risks are common to all businesses while others are industry
specific. The following review includes our approach to managing various risks.

OPERATIONAL RISKS

Exploration for and production of oil and natural gas can be hazardous,
involving natural disasters and other unforeseen occurrences such as blowouts,
cratering, fires and loss of well control, which can damage or destroy wells
or production facilities, injure or kill people, and damage property and the
environment. Because third party drilling contractors are used to drill our
wells, we may not realize the full benefit of worker's compensation laws in
dealing with their employees.

We seek to mitigate the foregoing risks by maintaining prudent levels
of insurance against many potential losses and liabilities arising from our
operations. However, in accordance with customary industry practice, we may not
be fully insured against these risks, nor may all such risks be insurable.

Unless we successfully replace our reserves, our production will decline,
resulting in lower revenues and cash flow. Replacing our reserves is
particularly important because most of our reserves are in the U.S. Gulf of
Mexico where wells normally have steeper rates of decline than onshore wells.
Exploring for oil and natural gas and developing oil and natural gas properties
require significant capital expenditures and involve a high degree of
financial risk. The budgeted costs of drilling, completing and operating wells
are often exceeded and can increase significantly when drilling costs rise and
rig supply tightens. Drilling may be unsuccessful for many reasons, including
weather, cost overruns, equipment shortages and mechanical difficulties.
Moreover, the successful drilling of an oil or gas well does not ensure a
profit on investment. Exploratory wells bear a much greater risk of loss than
development wells. A variety of factors, both geological and market-related,
can cause a well to become uneconomic or only marginally economic. In addition
to their costs, unsuccessful wells can harm our efforts to replace reserves.


                                       24
<PAGE>   27

We seek to limit our financial and operating risks in some projects by
participating in drilling with industry partners and operators. We believe this
strategy limits our risk exposure in high potential prospects. Additionally, we
have increasingly relied on advanced technologies, including 3D seismic
analysis, to define geologic risks, thereby enhancing the results of our
drilling efforts. We also seek to operate our projects in order to better
control drilling costs and timing of drilling.

ENVIRONMENTAL AND SAFETY RISKS

U.S. exploration, production and marketing operations are regulated extensively
at the federal, state and local levels. These regulations affect costs, manner
and feasibility of our operations. Changes in, or additions to, regulations
regarding the protection of the environment could increase our compliance costs
and may negatively impact our business. U.S. offshore oil and gas operations are
subject to regulations of the U.S. 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 damage.

In the U.K., deposits of substances or articles at sea from offshore oil and
gas operations are subject to the licensing control of the Ministry of
Agriculture, Fisheries and Food.

At present, we believe that our properties are being operated in compliance
with applicable environmental laws and regulations. We do not anticipate that
we 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 we are unable to quantify the ultimate
cost of compliance.

MARKETING RISKS

There is uncertainty as to the prices at which gas and oil we produce may be
sold, and it is possible that under some market conditions the production of
gas and oil from some of our 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 our control,
including market considerations, the proximity and capacity of gas and oil
pipelines and processing equipment and governmental regulation. In recent
years, markets for natural gas in the U.S. 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.

Prices for oil and natural gas are volatile and declined significantly during
the second half of 1998 and early 1999. Natural gas prices affect us more than
oil prices as natural gas was 76% (75% after royalties) of our 1999 equivalent
production, 80% (79% after royalties) of our 1998 production and 83% (before
and after royalties) of our 1997 production. In 1998, natural gas prices we
received were 17% lower than in 1997 and oil prices were 38% lower. Primarily
because of lower prices, we recorded ceiling test write-downs of the U.K.
assets in 1999 and 1998.

Most of the factors which affect natural gas and oil prices are beyond our
control, such as demand, worldwide economic conditions, weather conditions,
supply levels, import prices, political conditions in major oil producing
regions, especially the Middle East, and actions taken by the Organization of
Petroleum Exporting Countries ("OPEC").

We could be required to write-down the carrying value of our oil and natural gas
properties in the future if oil and natural gas prices are depressed for even a
short period of time, are unusually volatile or if we have substantial downward
revisions to our proved reserve quantities. Any such ceiling test write-down
would result in a charge to earnings and a reduction of shareholders' equity,
but would not impact our cash flow from operating activities. Once incurred,
these write-downs cannot be reversed at a later date.

YEAR 2000

The Year 2000 Issue arose because many computerized systems used two digits
rather than four to identify a year. Date-sensitive systems may recognize the
year 2000 as 1900 or some other date, resulting in errors when information
using year 2000 dates is processed. In addition, similar problems may have
arisen in some systems which used certain dates in 1999 to represent something
other than the date. Although the change in date has occurred, it is not
possible to conclude that all aspects of the Year 2000 Issue that may affect
us, including those related to customers, suppliers, or other third parties,
have been fully resolved.

We have interests in a substantial number of offshore oil and natural gas
production facilities that are operated by others. Production volumes are
transported through pipelines and processed through facilities that are also
operated by others. Computers are used extensively to control and operate such
pipelines and facilities in the oil and natural gas industry. As of the date of
this Form 10-K report, no Year 2000 Issue related event has occurred that
materially affects us, including shutdown of production, transportation or
processing facilities. Costs that we incurred in preparation for the Year 2000
Issue were not material.



                                       25

<PAGE>   28
CORPORATE GOVERNANCE

The Board of Directors and management of the Company support the guidelines for
corporate governance set forth by the Toronto Stock Exchange and the Company's
corporate governance practices were developed in accordance with these
guidelines.

THE BOARD'S MANDATE

The Board of Directors exercises overall responsibility for the management and
supervision of the Company's affairs. It has established processes, policies
and practices to guide its stewardship of the Company in the areas of strategic
planning; identification and management of the principal risks of the Company's
business; succession planning and management development; communications; and
internal control and management information. Management is responsible for
providing information and maintaining processes which enable the Board to
discharge its responsibilities. Administrative procedures govern the approval
of transactions, the delegation of authority and the signing of documents.

The Board of Directors is kept informed of the Company's operations through
regularly scheduled meetings of the Board and its committees and through
reports and analyses and discussions with management. During 1999, the
directors met at four regularly scheduled meetings. Five additional meetings
were held by telephone conference. Communications between the directors and
management occur as required in addition to the board and committee meetings.

The Board of Directors annually reviews and approves the Company's corporate
strategy. The Board reviews the Company's budget for the following fiscal year,
including operating and financial targets and approves the capital expenditures
for which management is responsible. As part of that process, the objectives of
the Chief Executive Officer and the Chief Operating Officer are reviewed.

Management performance, succession planning and management development are
regularly reviewed by the Compensation Committee and in turn by the Board of
Directors.

The Company's communications strategy and implementation is regularly reviewed
by the Board of Directors. The Board and appropriate Committees review the
Company's Annual Report to Shareholders, Management's Discussion and Analysis,
Management Information Circular, Annual Information Form, Form 10-K Annual
Report, quarterly financial statements, Interim Reports, Form 10-Q Reports and
news releases on major developments before they are distributed. The Company
provides information on its business and financial results on its internet web
site at www.chieftaininternational.com.

THE BOARD'S COMPOSITION

The Board of Directors is comprised of eight members. Having regard to the size
and complexity of the Company's business, the Board considers that eight is the
minimum number of directors required.

The Board of Directors is constituted with a majority of individuals who are
independent, unrelated directors. Three senior officers of the Company are
members of the Board. The Chairman of the Board is a non-executive Chairman who
has not held another office with the Company. The Board meets at least annually
with only the independent, unrelated members in attendance.

The Board of Directors has five committees, as follows. Each of the committees
has four members and all committees are comprised entirely of independent,
unrelated directors. Committees may engage external resources.

AUDIT COMMITTEE

The primary function of the Audit Committee is to assist the Board of Directors
in providing corporate oversight in the areas of financial reporting, internal
control and the audit process. The Committee regularly meets alone with Company
personnel and with the independent auditors. The independent auditors have
access to the Committee at any time. The Committee recommends to the Board for
its approval the financial statements and the annual appointment of external
auditors.

COMPENSATION COMMITTEE

The primary function of the Compensation Committee is to assist the Board of
Directors in carrying out its responsibilities by reviewing compensation
matters and making recommendations to the Board. It considers and recommends to
the Board for approval directors' compensation, appointment and remuneration of
officers and transactions under the share option plan. This Committee reviews
compensation and benefits policies, plans and budgets, salaries of certain
non-officer employees and succession planning.

NOMINATING AND CORPORATE GOVERNANCE COMMITTEE

The Nominating and Corporate Governance Committee assists the Board by
reviewing corporate governance and Board nomination matters and making
recommendations to the Board as appropriate. The Committee advises the Board on
such matters as


                                       26
<PAGE>   29

the size and composition of the Board of Directors and its committees, nominees
for the election of directors and corporate governance practices.

PENSION COMMITTEE

The Pension Committee reviews generally and makes recommendations to the Board
of Directors with regard to the Company's retirement plans, related agreements
and the appointment and performance of retirement fund investment managers.

RESERVE COMMITTEE

The primary function of the Reserve Committee is to review the Company's
externally disclosed oil and gas reserve estimates. The Committee reviews the
reports of the independent engineers charged with evaluating the Company's
reserves and also reviews the selection of the independent engineers and the
scope of their work.

OUTLOOK AND PROSPECTS FOR FUTURE GROWTH

OUR STRATEGY

Our strategy is to increase our reserves, production, revenue and cash flow
through exploration and development drilling and through the acquisition of
leasehold acreage and producing properties. The elements of our strategy
include the following:

o     Focus on the U.S. Gulf of Mexico region. We focus our operations on the
      U.S. Gulf of Mexico region where we have acquired a significant
      exploration acreage position and assembled a substantial 3D seismic
      database. We believe this region combines significant geological
      potential, reservoir size, quality and deliverability with favorable
      commodity pricing and attractive finding, development and operating costs.

o     Grow through exploration. We are pursuing an active technology-driven
      exploration program that is designed to balance projects with lower risk
      and moderate potential with drilling prospects which have higher risk and
      substantial potential. We generate exploration prospects through
      geological and geophysical analysis of 3D seismic and other data and also
      review prospects generated by others. Our Board of Directors has approved
      a 2000 budget of $86 million for exploration and development capital
      expenditures and we expect to use approximately $50 million of this amount
      for exploration activities. We are currently drilling or plan to drill
      approximately 27 exploratory and development wells in the U.S. Gulf of
      Mexico region in 2000. Approximately two-thirds of these will be
      exploration wells and the remainder are development wells to follow up the
      1999 discoveries.

o     Manage drilling risks through joint ventures and the use of advanced
      technologies. As described under Operational Risks on page 24.

o     Evaluate and pursue strategic acquisitions. We continually review
      opportunities to acquire leasehold acreage and producing properties. We
      seek to acquire properties that we believe have significant exploration
      potential and to increase our working interest in producing lease blocks
      when available to us on economically favorable terms.

OUR STRENGTHS

We believe that our future performance and historical success are directly
related to the following combination of strengths:

o     Substantial inventory of drilling projects in the U.S. Gulf of Mexico
      region. In the U.S. Gulf of Mexico region, we have generated an inventory
      of over 35 drilling prospects. All of these locations have been evaluated
      and defined using 3D seismic data. Our large inventory permits us to be
      flexible in project selection and in the timing of drilling. By
      identifying new exploration targets and acquiring additional acreage, we
      continually add to our drilling inventory.

o     Proven exploratory expertise. Our ability to define and participate in
      successful prospects in the U.S. Gulf of Mexico is demonstrated by our
      exploratory drilling success rate in the U.S. Gulf of Mexico region of 73%
      for 1999.

o     Experienced technical team. Our technical team is comprised of highly
      respected industry professionals with an average of more than twenty years
      of industry experience. We believe our exploration success is a direct
      result of this team's geologic, geophysical, engineering and technical
      analysis.

o     Financial flexibility. At December 31, 1999, $90 million was available
      under our revolving credit facility. We seek to maintain low levels of
      debt in order to be able to respond quickly to drilling or acquisition
      opportunities.


                                       27
<PAGE>   30
OUR LOOK FORWARD

The fundamentals for U.S. natural gas production remain very positive with the
U.S. Energy Information Administration reporting natural gas demand growing at
an average rate of two per cent annually while domestic natural gas
deliverability is showing a modest decline. Extremely mild weather, which had a
significant impact on natural gas demand in 1998, continues to be a factor.
Temperatures through much of the U.S. were considerably warmer than normal in
the fall and early winter of 1999. Natural gas in storage remains at relatively
high levels and has brought 2000 natural gas prices down somewhat, but
increasing demand and declining deliverability have prevented natural gas
prices from falling to the extremely low levels experienced in the first
quarter of 1999. At year end 1999, the American Gas Association reported that
storage volumes were 20% higher than comparative averages for 1995-1997, but 8%
lower than at year end 1998.

On the natural gas supply side, low commodity prices dramatically reduced
drilling for new supplies which contributed to an estimated 0.5% decline in
domestic production during 1999. The active rig count in the U.S. declined by
25% in 1999 to average 622 rigs from 831 in 1998, according to Baker Hughes. The
rig count was 943 in 1997 and 1,110 in 1990. Reduced demand for drilling rigs
was particularly acute in the U.S. Gulf of Mexico where the average number of
active rigs declined to 127 rigs in 1999 from 156 in 1998 and 168 in 1997. The
Gulf of Mexico Newsletter reported that only 712 wells were drilled in the U.S.
Gulf of Mexico in 1999 compared with 937 in 1998 and 1,124 in 1997. Moreover,
the number of reported discoveries fell to 87 in 1999 from 130 in 1998 and 142
in 1997. As 2000 began, 149 rigs were under contract for a utilization rate of
78% compared with 130 active rigs for a utilization rate of 73% at the end of
1998.

The foregoing supports the conclusion of many industry observers that the
natural gas supply and demand equation is tightening up in the U.S. This
balancing of natural gas supply and demand will confer benefits on properly
poised companies in our industry. We believe that adherence to our strategy
will bring continued growth, and maintain a strong balance sheet which will, in
turn, allow us to be opportunistic and to grow even during periods of low
natural gas and oil prices. We have achieved strong production growth of 10%,
11% and 9% in 1997, 1998 and 1999 respectively. Our planned 2000 exploration
and development program, which we expect to fund from operating cash flow and
our unsecured revolving credit facility, is expected to increase 2000
production volumes by 5 to 10% over 1999 levels. Early in 2000, we will benefit
from new production at the Northeast Wright field in Louisiana and new offshore
facilities will commence production as the year unfolds at High Island
A-510/A-531, High Island A-530, South Timbalier 196, Vermilion 267 and West
Cameron 613. Any delays in initial production from these properties would have
an effect on our 2000 production volumes.

Our capital expenditures can vary significantly as a result of exploration
success, availability of equipment and services and opportunities. We will
continue to monitor capital spending and adjust investment levels in relation
to cash flow projections. If reductions were required to be made to our
budgeted 2000 capital expenditures, economic merit and a longer term view would
be used to make such decisions. Specifically, fewer wildcat wells could be
drilled (either delayed or deleted), bidding at lease sales could be curtailed
and seismic data acquisition could be reduced. If our budgeted 2000 capital
expenditures were to be increased, for reasons other than cost overruns or
expenditures contingent on successful drilling, great care would be taken to
ensure that our associated human resources would be adequate. The nature of
such increased capital expenditures would be dependent upon the opportunities
that arise.

Our long-term growth is dependent upon our ability to effectively reinvest cash
flow. While increased production volumes will improve cash flow, oil and
natural gas prices will have the most significant effect on cash flow levels.
Our view of natural gas prices in the U.S. Gulf of Mexico region is optimistic.
The volatility that can occur in oil prices was clearly demonstrated during
1999. We believe that the control on oil prices that can be exerted by OPEC has
been amply demonstrated. Should OPEC continue to meet its production quota, we
expect that WTI prices in excess of $20 per bbl will prevail. For planning
purposes we have used a more conservative long-term average price of
approximately $18 per bbl. In order to relate the significance of natural gas
and oil prices and volumes to cash flow we have provided sensitivities that
demonstrate the estimated effect of price and volume changes on cash flow.

We expect continued low prices for U.K. production in the near term, largely due
to the excess supply of natural gas.

<TABLE>
<CAPTION>
                                                                  Impact on 2000 cash flow
SENSITIVITIES                                                 $ 000's        Per share (basic)
----------------------------------------------------------------------------------------------
<S>                                                              <C>               <C>

Change of $0.10 per mcf in the price of natural gas            $2,400              $0.15
Change of $1.00 per bbl in the price of oil                     1,500               0.09
Change of 10 mmcf/d                                             5,900               0.36
Change of 1000 bbls/d                                          $5,300              $0.32

</TABLE>


                                       28
<PAGE>   31

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

     Management's Report

     Auditors' Report

     Consolidated Balance Sheet as at December 31, 1999 and 1998

     Consolidated Statement of Income (Loss) and Deficit for the years ended
     December 31, 1999, 1998 and 1997

     Consolidated Statement of Cash Flows for the years ended December 31,
     1999, 1998 and 1997

     Notes to Consolidated Financial Statements

     Supplementary Financial Information (Unaudited)


                                       29
<PAGE>   32


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/ R.J. Stefure
S.A. Milner                                      R.J. Stefure
President and Chief Executive Officer            Vice President and Controller

February 3, 2000


                                       30
<PAGE>   33
AUDITORS' REPORT

We have audited the consolidated balance sheets of Chieftain International,
Inc. as at December 31, 1999 and 1998 and the consolidated statements of income
(loss) and deficit and cash flows for each of the years in the three-year
period ended December 31, 1999. 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 Canadian 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,
1999 and 1998 and the results of its operations and its cash flows for each of
the years in the three-year period ended December 31, 1999 in accordance with
Canadian generally accepted accounting principles.



/s/ PricewaterhouseCoopers LLP
Chartered Accountants
Edmonton, Alberta

February 3, 2000



                                       31
<PAGE>   34
CONSOLIDATED BALANCE SHEET

CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES

<TABLE>
<CAPTION>
(Full Cost Method of Accounting) as at December 31,                       1999            1998
                                                                       ---------       ---------
                                                                         (U.S. $ in thousands)

<S>                                                                    <C>             <C>
ASSETS
Current assets:
  Cash and short-term deposits                                         $  19,368       $  10,613
  Accounts receivable                                                     18,855          14,030
  Other                                                                      750             282
                                                                       ---------       ---------
                                                                          38,973          24,925
                                                                       ---------       ---------
Capital assets, at cost:
  Natural resource properties including exploration and
    development thereon (Note 1(e))                                      607,401         552,380
  Other capital assets                                                     2,157           2,119
                                                                       ---------       ---------
                                                                         609,558         554,499
  Less: Accumulated depletion and amortization                           332,409         266,022
                                                                       ---------       ---------
                                                                         277,149         288,477
Deferred income taxes                                                     14,636           5,182
                                                                       ---------       ---------
                                                                       $ 330,758       $ 318,584
                                                                       =========       =========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
  Accounts payable and accrued                                         $  25,369       $  22,533

Long-term debt (Note 2)                                                   10,000          40,000

Abandonment cost accrual                                                   8,595           7,421

Deferred income taxes                                                     15,693          13,684

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 -
      16,224,059 common shares (1998 - 13,355,891)                       237,076         189,108
  Contributed surplus                                                         26              --
  Deficit                                                                (29,404)        (17,565)
                                                                       ---------       ---------
                                                                         271,101         234,946
                                                                       ---------       ---------
                                                                       $ 330,758       $ 318,584
                                                                       =========       =========
</TABLE>

Approved by the Board:


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


                                       32
<PAGE>   35
CONSOLIDATED STATEMENT OF INCOME (LOSS) AND DEFICIT

CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES

<TABLE>
<CAPTION>
Year ended December 31,                                     1999             1998               1997
                                                        ------------     ------------       ------------
                                                (U.S.$ in thousands except shares and per share amounts)

<S>                                                     <C>              <C>                <C>
Production revenue                                      $     91,507     $     74,861       $     84,219
  Less: royalties                                             16,141           13,246             14,592
                                                        ------------     ------------       ------------
Production revenue, after royalties                           75,366           61,615             69,627
Interest and other revenue (Note 5)                            1,081            2,776              2,428
                                                        ------------     ------------       ------------
                                                              76,447           64,391             72,055
                                                        ------------     ------------       ------------

Production costs                                              14,320           16,355             13,325
General and administrative expenses                            4,580            4,796              4,308
Interest                                                       2,496              437                 --
Depletion and amortization                                    51,385           42,081             36,951
Additional depletion: Libyan properties                       11,393            5,144                 --
                      U.K. properties                          4,793            1,100                 --
                                                        ------------     ------------       ------------
                                                              88,967           69,913             54,584
                                                        ------------     ------------       ------------
Income (loss) before income taxes and dividends
  on preferred shares of a subsidiary                        (12,520)          (5,522)            17,471
Income taxes (Note 6):
  Current                                                         11               14                  7
  Deferred                                                    (5,634)          (1,423)             7,304
                                                        ------------     ------------       ------------
                                                              (5,623)          (1,409)             7,311
                                                        ------------     ------------       ------------
Income (loss) before dividends on preferred shares
  of a subsidiary                                             (6,897)          (4,113)            10,160
Dividends paid on preferred shares of a subsidiary             4,942            4,942              4,942
                                                        ------------     ------------       ------------
Net income (loss) applicable to common shares                (11,839)          (9,055)             5,218
Deficit, beginning of year                                   (17,565)          (7,089)           (12,307)
Cost of purchase of common shares in excess
  of stated capital (Note 4)                                      --           (1,421)                --
                                                        ------------     ------------       ------------

Deficit, end of year                                    $    (29,404)    $    (17,565)      $     (7,089)
                                                        ============     ============       ============

Net income (loss) per common share (Note 8)             $      (0.86)    $      (0.67)      $       0.38
                                                        ============     ============       ============

Weighted average number of common shares outstanding      13,701,419       13,480,067         13,620,728
                                                        ============     ============       ============
</TABLE>

                                       33
<PAGE>   36
CONSOLIDATED STATEMENT OF CASH FLOWS

CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES


<TABLE>
<CAPTION>

Year ended December 31,                                     1999           1998          1997
-----------------------------------------------------------------------------------------------
                                                                   (U.S.$ in thousands)

<S>                                                       <C>            <C>           <C>
Operating activities:
  Net income (loss) applicable to common shares           $(11,839)      $ (9,055)     $  5,218
  Items not requiring a current cash outlay:
    Depletion and amortization                              67,571         48,325        36,951
    Deferred income taxes                                   (5,634)        (1,423)        7,304
                                                          --------       --------      --------
  Cash flow from operations                                 50,098         37,847        49,473
  Change in non-cash operating working
    capital (Note 7)
        Accounts receivable                                 (4,825)        (3,168)          337
        Other current assets                                  (468)           324          (313)
        Accounts payable and accrued                         3,830            164           992
                                                          --------       --------      --------
                                                            48,635         35,167        50,489
                                                          --------       --------      --------
Financing activities:
  Issue of common shares                                    50,321            437           975
  Purchase of common shares for cancellation                   (80)        (5,902)         (849)
  Increase in long-term debt                                 5,000         40,000            --
  Decrease in long-term debt                               (35,000)            --            --
  Financing costs                                           (4,058)            --            --
                                                          --------       --------      --------
                                                            16,183         34,535           126
                                                          --------       --------      --------
Investing activities:
  Lease acquisition, exploration and
    development costs                                      (55,176)       (91,690)      (69,453)
  Sale of producing properties                                 155             --            --
  Purchase of producing gas and oil properties                  --           (883)           --
                                                          --------       --------      --------
                                                           (55,021)       (92,573)      (69,453)
  Purchase of other capital assets                             (48)           (93)         (324)
  Change in investing accounts payable and
    accrued                                                   (994)         6,652         3,638
                                                          --------       --------      --------
                                                           (56,063)       (86,014)      (66,139)
                                                          --------       --------      --------
Change in cash and short-term deposits                       8,755        (16,312)      (15,524)
Cash and short-term deposits, beginning of year             10,613         26,925        42,449
                                                          --------       --------      --------
Cash and short-term deposits, end of year                 $ 19,368       $ 10,613      $ 26,925
                                                          ========       ========      ========
</TABLE>


                                       34
<PAGE>   37
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(December 31, 1999, 1998 and 1997)
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES

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

     1.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

          (a)  ACCOUNTING PRINCIPLES

               The Company's financial statements are prepared in conformity
               with Canadian generally accepted accounting principles. The
               preparation of financial statements in conformity with generally
               accepted accounting principles requires management to make
               informed judgements and estimates. Actual results may differ from
               those estimates. Material differences between Canadian and U.S.
               accounting principles that affect the Company are referred to in
               Note 12, 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
               U.S. subsidiary which in 1992 issued 2,726,700 preferred shares
               to the public. These preferred shares are convertible into common
               shares of Chieftain International, Inc. See Note 3.

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

          (c)  FOREIGN CURRENCY TRANSLATION

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

          (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 natural gas industry credit risks. Long-term debt
               is subject to normal floating interest rate risk.


                                       35
<PAGE>   38
          (e)  NATURAL RESOURCE PROPERTIES

               The Company accounts for natural 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 natural 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 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 natural gas
               and oil produced by the Company may be sold. The application of
               such ceiling test to U.S. 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 $6,310,000 (1998 -
               $2,849,000), after providing for tax recoveries of $5,083,000
               (1998 - $2,295,000), was recorded in respect of the Libyan
               concessions which resulted in all Libyan costs being written off
               as at December 31, 1999. A write-down of $2,654,000 (1998 -
               $609,000), after providing for tax recoveries of $2,139,000 (1998
               - $491,000), was recorded in respect of the U.K. properties.

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


<TABLE>
<CAPTION>
               As at December 31,                 1999      1998      1997
               -----------------------------------------------------------
               <S>                             <C>       <C>       <C>
               Oil (per bbl)                   $ 20.30   $ 12.35   $ 16.92
               Ngls (per bbl)                  $ 21.67   $ 10.19   $ 15.14
               Oil and ngls (per bbl)          $ 20.40   $ 12.27   $ 16.69
               Natural gas (per mcf)           $  2.51   $  2.15   $  2.74
</TABLE>

               A field price of $0.99 (1998 - $1.74; 1997 - $1.76) per mcf was
               used in the determination of the Company's U.K. future net
               revenues for purposes of the ceiling test.


                                       36

<PAGE>   39
               Depletion rates per physical unit of U.S. production are as
               follows:

<TABLE>
<CAPTION>
                                               Natural Gas    Oil and ngls
                                                (per mcf)       (per bbl)
                                               -----------    ------------
               <S>                                <C>            <C>
               Year ended December 31, 1997       $ 1.11         $ 6.68
               Year ended December 31, 1998       $ 1.16         $ 6.97
               YEAR ENDED DECEMBER 31, 1999       $ 1.25         $ 7.50
</TABLE>

               The depletion rate per physical unit of U.K. natural gas
               production was $1.24 per mcf for the year ended December 31, 1999
               (1998 - $0.81; 1997 - $0.81).

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

<TABLE>
<CAPTION>

               Year ended December 31,       1999      1998      1997
               -----------------------      ------    ------    ------
                                                  (in thousands)
               <S>                          <C>       <C>       <C>
               Lease acquisition            $  765    $  857    $  694
               Exploration                   1,581     1,740     1,470
               Development                   1,601     1,715     1,387
                                            ------    ------    ------
                                            $3,947    $4,312    $3,551
                                            ======    ======    ======
</TABLE>

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

          (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 (Loss) and Deficit as
               depletion and amortization.


                                       37
<PAGE>   40
          (g)  INCOME TAXES

               Effective with the fourth quarter of 1999, the Company
               retroactively adopted the liability method of accounting for
               income taxes, such method being required to be adopted no later
               than 2000 under Canadian generally accepted accounting
               principles. Applying this method, deferred income taxes are
               recognized, using applicable, enacted income tax rates, for the
               future income tax consequences attributable to differences
               between the financial statement carrying values and their
               respective income tax bases. The effect on deferred income tax
               assets and liabilities of a change in tax rates is included in
               income in the period that includes the enactment date. Deferred
               income tax assets are evaluated and if realization is considered
               "more likely than not", no valuation allowance is provided.

               The retroactive application of this policy had no material effect
               on the Company and therefore no restatement of prior periods has
               been made.

     2.   REVOLVING CREDIT AND LONG-TERM DEBT

          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 U.S. base rate, or at
          Bankers' Acceptance rates or LIBOR plus applicable margins. Certain
          financial tests are required to be met quarterly. Under this facility,
          $10 million was utilized at December 31, 1999 (1998 - $40 million),
          carrying a weighted average interest rate of 7.00% (1998 - 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 U.S. The preferred shares are
          redeemable, at the option of Funding, at $25.4028 per share during
          2000, $25.2014 per share during 2001 and $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.


                                       38
<PAGE>   41
      4.  SHARE CAPITAL

          (a) COMMON SHARES

<TABLE>

Year ended December 31,                  1999                    1998                    1997
                                  ---------------------   ---------------------    ----------------------
<S>                               <C>         <C>         <C>        <C>           <C>         <C>
                                      Number      Share       Number      Share       Number       Share
                                          of    Capital           of    Capital           of     Capital
                                      Shares    Account       Shares    Account       Shares     Account
                                  ----------  ---------   ----------  ---------   ----------   ---------
                                               (in thousands except number of shares)

Balance, beginning of year        13,355,891  $ 189,108   13,622,375  $ 192,845   13,591,763   $ 192,381
  Share options exercised                668          9       28,216        437       66,912         975
  Share purchased and cancelled*      (7,500)      (106)    (294,700)    (4,174)     (36,300)       (511)
  Shares issued for cash**         2,875,000     48,065            -          -            -           -
                                  ----------  ---------   ----------  ---------   ----------   ---------
Balance, end of year              16,224,059  $ 237,076   13,355,891  $ 189,108   13,622,375   $ 192,845
                                  ==========  =========   ==========  =========   ==========   ==========
</TABLE>

 * Pursuant to normal course issuer bid.
** Reduced by costs of issue of $4,058, less related deferred taxes of $1,811.


               In the fourth quarter of 1999, the Company sold 2,875,000 common
               shares, by way of a public offering in the U.S., at $17.50
               per share.

          (b)  COMMON SHARES RESERVED

               At December 31, 1999, 1,130,207 (1998 - 1,130,875; 1997 -
               1,159,091) of the authorized but unissued common shares
               of the Company were reserved for issuance under the Share
               Option Plan. See Note 4(d).

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

          (c)  CONTRIBUTED SURPLUS

               Contributed surplus represents the excess of original net
               issue price over purchase price of shares purchased and
               cancelled pursuant to successive issuer bids, the most
               recent of which expired November 1, 1999.

          (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. 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 and, therefore, no compensation expense is recognized.
               Proceeds arising from the exercise of share options are
               credited to share capital. At December 31, 1999 options
               were outstanding to 46 participants in the Plan.


                                       39
<PAGE>   42
          The following is a summary of activity related to the Plan for the
          years ended December 31, 1999, 1998 and 1997.


<TABLE>
Year ended December 31,                        1999                          1998                     1997
                                      ---------------------       ----------------------       ---------------------
                                                   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     1,083,857      $16.74        1,057,673      $16.47          909,253      $15.10
     Granted                           180,000       13.44           65,000       21.08          228,000       21.35
     Exercised                            (668)      13.63          (28,216)      15.49          (66,912)      14.47
     Forfeited                          (4,000)      22.54          (10,600)      20.07          (12,668)      16.06
     Expired                          (140,000)      13.61               --          --             --          --
                                     ---------                    ---------                    ---------
Outstanding at end of year           1,119,189       16.58        1,083,857       16.74        1,057,673       16.47
                                     =========                    =========                    =========
Options exercisable at year end        824,521                      869,858                      707,738
                                     =========                    =========                    =========

</TABLE>


          The following table summarizes information about options outstanding
          at December 31, 1999.


<TABLE>
                                          Options Outstanding                         Options Exercisable
                       ------------------------------------------------------      -------------------------
                                                  Weighted          Weighted                       Weighted
   Range of               Number                   Average           Average         Number         Average
     Option                   of                 Remaining            Option             of          Option
      Price               Shares          Contractual Life             Price         Shares           Price
--------------         ----------         ----------------          --------        --------       ---------
 <S>                   <C>                     <C>                    <C>            <C>              <C>
$11.43 - 15.63            718,855              6.0 years              $14.20         553,855          $14.56
 18.00 - 20.87            133,334              4.3 years               19.06         101,667           19.35
 21.23 - 23.75            267,000              7.5 years               21.74         168,999           21.69
                        ---------                                                    -------
                        1,119,189                                                    824,521
                        =========                                                    =======

</TABLE>

     5. INTEREST AND OTHER REVENUE

        Interest and other revenue for 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.






                                       40


<PAGE>   43
     6.   INCOME TAXES

          Income tax expense is made up of the following components:

<TABLE>
<CAPTION>
Year ended December 31,                                          1999                    1998                   1997
                                                         CANADA         U.S.     CANADA          U.S.     CANADA     U.S.
---------------------------------------------------------------------------------------------------------------------------
                                                                                    (in thousands)
<S>                                                    <C>            <C>       <C>            <C>       <C>       <C>
Income (loss) before income taxes and dividends
  on preferred shares of a subsidiary                  $ (18,254)     $ 5,734   $ (6,829)      $ 1,307   $ 2,072   $ 15,399
                                                       =========      =======   ========       =======   =======   ========
Income taxes (recovery)
  Current                                              $      11      $    --   $     14       $    --   $     7   $     --
  Deferred                                                (7,643)       2,009     (1,740)          317     2,007      5,297
                                                       ---------      -------   --------       -------   -------   --------
                                                       $  (7,632)     $ 2,009   $ (1,726)      $   317   $ 2,014   $  5,297
                                                       =========      =======   ========       =======   =======   ========
</TABLE>

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

<TABLE>
<CAPTION>
          Year ended December 31,               1999        1998        1997
          ---------------------------------------------------------------------
                                                        (in thousands)
          <S>                                <C>          <C>         <C>
          Tax at statutory rate of 44.62%
            (Combined Canadian federal and
            provincial rate)                 $ (5,587)    $ (2,465)   $  7,796
          Add (deduct) the effect of:
            Lower income tax rate on
              earnings of U.S. subsidiaries      (496)         (81)     (1,373)
            Canadian income tax on exchange
              loss which is eliminated
              upon consolidation                  909          631         429
            Other                                (449)         506         459
                                             --------     --------    --------
          Tax at effective rate              $ (5,623)    $ (1,409)   $  7,311
                                             ========     ========    ========
          Effective tax rate                     44.9%        25.5%       41.8%
                                             ========     ========    ========
</TABLE>

          Temporary differences comprising the deferred tax assets (liabilities)
          are as follows:

<TABLE>
<CAPTION>
          As at December 31,                              1999           1998
          ----------------------------------------------------------------------
                                                             (in thousands)
          <S>                                          <C>            <C>
          Deferred tax assets
            Depletion and amortization                 $  10,679      $   3,468
            Financing costs                                2,005            390
            Loss carryforwards                            28,106         20,593
            Other                                            495            382
                                                       ---------      ---------
                                                          41,285         24,833
                                                       ---------      ---------
          Deferred tax liabilities
            Depletion and amortization                   (42,342)       (33,232)
            Other                                             --           (103)
                                                       ---------      ---------
                                                         (42,342)       (33,335)
                                                       ---------      ---------
          Net deferred tax liabilities                 $  (1,057)     $  (8,502)
                                                       =========      =========
</TABLE>


                                       41
<PAGE>   44
          At December 31, 1999 the Company's U.S. net operating tax losses
          carried forward amounted to $75,056,000 of which $6,119,000,
          $2,835,000, $6,139,000, $18,007,000, $3,773,000, $2,090,000,
          $16,088,000 and $20,005,000 expire in the years 2005, 2007, 2009,
          2010, 2011, 2012, 2018 and 2019, respectively. Canadian net operating
          tax losses carried forward amounted to $3,277,000 of which $2,108,000,
          $248,000 and $921,000, expire in the years 2003, 2005 and 2006,
          respectively. The Company is of the opinion that the tax benefit of
          these tax losses will be realized.

     7.   SUPPLEMENTAL CASH FLOW INFORMATION

          Net cash outflows for (inflows from) income taxes were $(12,000),
          $14,000 and $141,000 for the years 1999, 1998 and 1997, respectively.
          Cash outflows for long-term debt interest were $2,601,000 and $628,000
          in 1999 and 1998, respectively.

     8.   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 preferred
          share dividends and the amount of imputed interest on share option
          proceeds. Earnings were not diluted during the periods shown.

     9.   PENSION COSTS AND OBLIGATIONS

          The Company contributed $145,418, $145,300 and $144,254 for 1999, 1998
          and 1997, respectively, to defined contribution plans. Under a
          supplementary defined contribution plan established in 1991, costs of
          $216,401, $198,294 and $162,384 for 1999, 1998 and 1997, respectively,
          and the related liability are recorded in the accounts.

          The Company has established no other retirement benefit plans.

     10.  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 U.S. gas, oil and ngls produced by the Company are marketed by a
          single aggregator. Production revenues, net of royalties, associated
          with the aggregator were $59,665,000 (1998-$46,340,000;
          1997-$50,250,000). 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
          $9,710,000 (1998-$8,207,000; 1997-$10,880,000). The Company believes
          that alternative marketing arrangements would be readily available for
          its gas, oil and liquids.



                                       42
<PAGE>   45

<TABLE>
<CAPTION>
                                                       1999       1998       1997
                                                     --------   --------   --------
                                                             (in thousands)
          <S>                                        <C>        <C>        <C>
          Production revenue, net of royalties
            U.S.                                     $ 71,487   $ 56,199   $ 63,227
            U.K.                                        3,582      4,411      6,231
            Libya                                         297      1,005        169
                                                     --------   --------   --------
          Total production revenue, net of
            royalties                                  75,366     61,615     69,627
          Interest and other revenue                    1,081      2,776      2,428
                                                     --------   --------   --------
          Total revenue                              $ 76,447   $ 64,391   $ 72,055
                                                     ========   ========   ========
          Net capital assets
            U.S.                                     $274,904   $267,020   $213,856
            U.K.                                        1,994     11,337     14,733
            Canada and other                              251        285        328
            Libya                                          --      9,835     14,373
                                                     --------   --------   --------
                                                     $277,149   $288,477   $243,290
                                                     ========   ========   ========
</TABLE>


         As at December 31, 1999, the Company had entered into natural gas
         forward contracts with the aggregator and an oil forward contract with
         the regional refiner. The forward contracts, which are only for 2000
         production, are for the physical delivery of natural gas volumes
         totalling 6.1 bcf, at an average price of $2.49 per mcf, and for the
         physical delivery of oil volumes of 90 mbbls, at an average price of
         $19.00 per bbl. The value of these contracts would not be materially
         different using December 31, 1999 prices.

     11. UNCERTAINTY DUE TO THE YEAR 2000

         The Year 2000 Issue arises because many computerized systems use two
         digits rather than four to identify a year. Date-sensitive systems may
         recognize the year 2000 as 1900 or some other date, resulting in errors
         when information using year 2000 dates is processed. In addition,
         similar problems may arise in some systems which use certain dates in
         1999 to represent something other than a date. Although the change in
         date has occurred, it is not possible to conclude that all aspects of
         the Year 2000 Issue that may affect the Company, including those
         related to customers, suppliers, or other third parties, have been
         fully resolved.

     12. U.S. ACCOUNTING PRINCIPLES

         (a) FULL COST ACCOUNTING

             U.S. full cost accounting rules differ materially from the Canadian
             full cost accounting guidelines followed by the Company. In
             determining the limitation on carrying values, U.S. rules require
             the discounting of future net revenues at 10%, and Canadian
             guidelines require the use of undiscounted future net revenues and
             the deduction of estimated future administrative and financing
             costs. During 1999 and 1998 impairment adjustments would have been
             required under U.S. accounting rules. The quarterly test required
             by U.S. accounting rules, using a March 31, 1999 U.K. natural gas
             price of $0.84 per mcf to determine future net revenues, would have


                                       43
<PAGE>   46
               resulted in a write-down of U.K. property carrying costs at March
               31, 1999 of $7.1 million and, after providing for tax recoveries
               of $3.1 million, a net charge to operations of $4.0 million.
               Using December 31, 1998 U.S. natural gas and oil prices of $2.15
               per mcf and $9.72 per bbl, and June 30, 1998 U.S. natural gas and
               oil prices of $2.09 per mcf and $12.40 per bbl to determine
               future net revenues, would have resulted in a write-down of U.S.
               property carrying costs of $65.5 million and, after providing for
               tax recoveries of $22.9 million, a net charge to operations of
               $42.6 million, at December 31, 1998; and $24.7 million and, after
               providing for tax recoveries of $8.6 million, a net charge to
               operations of $16.1 million, at June 30, 1998. Such write-downs
               will result in reduced depletion expense, under U.S. rules, for
               subsequent periods. Under Canadian guidelines the test resulted
               in a write-down of U.K. property carrying costs of $4.8 million
               (1998 - $1.1 million) and, after providing for tax recoveries of
               $2.1 million (1998 - $0.5 million), a net charge to operations of
               $2.7 million (1998 - $0.6 million) at December 31; no
               corresponding write-downs were required under U.S. accounting
               rules.

          (b)  EARNINGS PER SHARE

               U.S. 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.

          (c)  EFFECT ON EARNINGS

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

<TABLE>
<CAPTION>
Year ended December 31,                          1999          1998          1997
-------------------------------------------------------------------------------------
                                   (in thousands except shares and per share amounts)
<S>                                        <C>            <C>             <C>
Net income (loss) applicable to common
   shares, as reported                      $   (11,839)   $    (9,055)   $     5,218
Additional depletion difference                  (2,311)       (89,153)            --
                                            -----------    -----------    -----------
                                                (14,150)       (98,208)         5,218
Reduction in depletion expense                   17,623          4,235          3,177
Reduction (increase) in deferred tax
   provision                                     (5,440)        30,010           (885)
                                            -----------    -----------    -----------

Net income (loss) applicable to common
   shares under U.S. accounting principles  $    (1,967)   $   (63,963)   $     7,510
                                            ===========    ===========    ===========

Net income (loss) per common share
   under U.S. accounting principles:
      Basic                                 $     (0.14)   $     (4.75)   $      0.55
                                            ===========    ===========    ===========
      Fully diluted                         $     (0.14)   $     (4.75)   $      0.54
                                            ===========    ===========    ===========
Fully diluted common shares outstanding      13,701,419     13,480,067     13,858,593
                                            ===========    ===========    ===========

</TABLE>

                                       44
<PAGE>   47

          (d)  EFFECT ON BALANCE SHEET

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

<TABLE>
<CAPTION>
               As at December 31,                1999                    1998
                                         ----------------------    ---------------------
                                                     Under U.S.               Under U.S.
                                            As       Accounting       As      Accounting
                                         Reported    Principles    Reported   Principles
                                         --------    ----------    --------   ----------
                                                        (in thousands)
               <S>                       <C>         <C>           <C>        <C>
               Net capital assets         $ 277,149   $  189,501    $ 288,477  $  185,517
               Deferred tax - asset          14,636       30,238        5,182      28,233
               Deferred tax - liability      15,693            -       13,684           -
               Deficit                      (29,404)     (85,757)     (17,565)    (83,790)

</TABLE>

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

          (e)  INCOME TAX DISCLOSURES

               Temporary differences comprising the deferred tax assets
               (liabilities) are as follows:

<TABLE>
<CAPTION>
               As at December 31,                           1999         1998
               ------------------                           ----         ----
                                                             (in thousands)
               <S>                                     <C>            <C>
               Deferred tax assets
                  Depletion and amortization              $ 11,561      $ 6,971
                  Financing costs                            2,005          390
                  Loss carryforwards                        28,106       20,593
                  Other                                        495          382
                                                          --------      -------
                                                            42,167       28,336
                                                          --------      -------
               Deferred tax liabilities
                  Depletion and amortization               (11,929)           -
                  Other                                          -         (103)
                                                          --------      -------
                                                           (11,929)        (103)
                                                          --------      -------
               Net deferred tax assets                    $ 30,238      $ 28,233
                                                          ========      ========
</TABLE>



                                       45
<PAGE>   48

          Provisions for deferred income taxes are as follows:

<TABLE>
<CAPTION>

Year ended December 31,                                   1999                           1998                          1997
                                                ----------------------         ----------------------        ---------------------
                                                  Canada        U.S.             Canada        U.S.            Canada       U.S.
                                                ----------------------------------------------------------------------------------
                                                                                (in thousands)
<S>                                             <C>          <C>               <C>         <C>               <C>         <C>

Income (loss) before income taxes and
  dividends on preferred shares of
  a subsidiary                                  $ (17,492)    $ 20,284         $  (5,002)    $(85,440)        $  3,019    $ 17,629
                                                =========     ========         =========     ========         ========    ========
Provision for deferred income taxes             $  (7,248)    $  7,054         $    (921)    $(30,512)        $  2,122    $  6,067
                                                =========     ========         =========     ========         ========    ========
</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,                                                             1999               1998               1997
----------------------------------------------------------------------------------------------------------------------------------
                                                                                                  (in thousands)
<S>                                                                            <C>                <C>                  <C>

Tax at statutory Canadian rate of 44.62%                                        $   1,247          $ (40,355)           $   9,213
  Lower income tax rate on earnings of U.S. subsidiaries                           (1,823)             7,830               (1,617)
  Canadian income tax on exchange loss which is eliminated
    upon consolidation                                                                909                631                  429
  Exchange revaluation of Canadian deferred tax assets                               (553)               280                  194
  Other                                                                                37                195                  (23)
                                                                                ---------           --------            ---------
Tax at effective rate                                                           $    (183)          $(31,419)           $   8,196
                                                                                =========           ========            =========
Effective tax rate                                                                   (6.6)%             34.7%                39.7%
                                                                                =========           ========            =========

</TABLE>

          (f)  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. U.S. accounting principles require
               disclosure of the impact on earnings and earnings per share of
               the value of options granted after 1994, calculated in accordance
               with FAS 123. Such impact, calculated using the Black-Scholes
               option pricing model and resulting in option fair values of
               $7.75, $10.61 and $11.49, applying risk-free interest rates of
               5.68%, 5.64% and 6.85% for options granted in 1999, 1998 and
               1997, respectively, and assuming ten year expected option lives,
               no dividend yields and expected volatilities of 28%, 25% and 24%
               on a weighted average basis, would amount to a net of tax charge
               to income (loss) of $1,255,000 (1998 - $1,502,000; 1997 -
               $1,348,000). After reflecting this charge, pro forma net income
               (loss) applicable to common shares under U.S. accounting
               principles would be $(3,222,000), (1998 - $(65,465,000); 1997 -
               $6,162,000); pro forma net income (loss) per common share under
               U.S. accounting principles would be $(0.24), (1998 - $(4.86);
               1997 - $0.45); and pro forma fully diluted earnings (loss) per
               common share under U.S. accounting principles would be $(0.24),
               (1998 - $(4.86); 1997 - $0.45). These effects are not necessarily
               indicative of those to be expected in future years.


                                       46
<PAGE>   49
          SUPPLEMENTARY FINANCIAL INFORMATION
          CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
          DECEMBER 31, 1999

          (Unaudited)

          RESERVE INFORMATION

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

TOTAL PROVED RESERVES-
BEFORE ROYALTY DEDUCTIONS:
<TABLE>
<CAPTION>
                                                     Natural Gas-mmcf                  Oil and ngls-mbbls*
                                                U.S.       U.K.      Total                      U.S.
                                              -------     ------    -------                    ------
<S>                                            <C>        <C>       <C>                        <C>
December 31, 1997                              131,126    18,317    149,443                    12,947
  Purchase of producing properties               4,745        --      4,745                        18
  Revision of previous estimates                10,683    (5,119)     5,564                    (1,478)
  Extensions, discoveries and other additions   29,360        --     29,360                     4,871
  Sale of proved properties                         --        --         --                        --
  Production                                   (26,960)   (3,088)   (30,048)                   (1,158)
                                               -------    ------    -------                    ------
December 31, 1998                              148,954    10,110    159,064                    15,200
  PURCHASE OF PRODUCING PROPERTIES                  --        --         --                        --
  REVISION OF PREVIOUS ESTIMATES                (5,635)     (151)    (5,786)                    1,602
  EXTENSIONS, DISCOVERIES AND OTHER ADDITIONS   64,127        --     64,127                     2,152
  SALE OF PROVED PROPERTIES                         --        --         --                        --
  PRODUCTION                                   (27,536)   (3,583)   (31,119)                   (1,644)
                                               -------    ------    -------                    ------
DECEMBER 31, 1999                              179,910     6,376    186,286                    17,310
                                               =======    ======    =======                    ======
</TABLE>

TOTAL PROVED RESERVES-
AFTER ROYALTY DEDUCTIONS:
<TABLE>
<CAPTION>
                                                     Natural Gas-mmcf                   Oil and ngls-mbbls*
                                                 U.S.      U.K.      Total                      U.S.
                                               -------    ------    -------                    ------
<S>                                            <C>        <C>       <C>                        <C>
December 31, 1997                              106,780    18,317    125,097                    11,253
  Purchase of producing properties               3,512        --      3,512                        14
  Revision of previous estimates                 7,819    (5,119)     2,700                    (1,316)
  Extensions, discoveries and other additions   22,268        --     22,268                     4,142
  Sale of proved properties                         --        --         --                        --
  Production                                   (21,416)   (3,088)   (24,504)                     (986)
                                               -------    ------    -------                    ------
December 31, 1998                              118,963    10,110    129,073                    13,107
  PURCHASE OF PRODUCING PROPERTIES                  --        --         --                        --
  REVISION OF PREVIOUS ESTIMATES                (4,707)     (151)    (4,858)                    1,475
  EXTENSIONS, DISCOVERIES AND OTHER ADDITIONS   51,251        --     51,251                     1,753
  SALE OF PROVED PROPERTIES                         --        --         --                        --
  PRODUCTION                                   (21,950)   (3,583)   (25,533)                   (1,389)
                                               -------    ------    -------                    ------
DECEMBER 31, 1999                              143,557     6,376    149,933                    14,946
                                               =======    ======    =======                    ======
</TABLE>

* 20,100 (1998-26,800) barrels of natural gas liquids, before and after royalty
deductions, associated with the U.K. gas reserves are not included in this
table.



                                       47
<PAGE>   50
(Unaudited)

PROVED DEVELOPED PRODUCING RESERVES -
BEFORE ROYALTY DEDUCTIONS:

<TABLE>
<CAPTION>
                                Natural Gas - mmcf         Oil and ngls - mbbls
                         -------------------------------
                          U.S.        U.K.        Total             U.S.
                         ------      ------       ------   --------------------
<S>                      <C>         <C>          <C>       <C>
December 31, 1997        55,013      18,317       73,330            8,209
December 31, 1998        70,082      10,108       80,190            5,430
DECEMBER 31, 1999        63,822       6,376       70,198            7,447

</TABLE>

PROVED DEVELOPED PRODUCING RESERVES -
AFTER ROYALTY DEDUCTIONS:

<TABLE>
<CAPTION>

                                Natural Gas - mmcf         Oil and ngls - mbbls
                         -------------------------------
                          U.S.        U.K.        Total             U.S.
                         ------      ------       ------   --------------------
<S>                      <C>         <C>          <C>       <C>
December 31, 1997        43,979      18,317       62,296            7,241
December 31, 1998        55,418      10,108       65,526            4,739
DECEMBER 31, 1999        50,531       6,376       56,907            6,580

</TABLE>



                                       48
<PAGE>   51
(Unaudited)

RESULTS OF OPERATIONS FOR GAS AND OIL PRODUCING ACTIVITIES

<TABLE>
<CAPTION>
Year ended December 31,                   1999          1998           1997
------------------------------          --------      --------       --------
                                                   (in thousands)
<S>                                     <C>           <C>            <C>
U.S.
  Revenue - net of royalties            $ 71,487      $ 56,199       $ 63,227
  Production costs                       (18,128)      (15,675)       (14,901)
  Depletion and amortization             (46,796)      (39,460)       (33,414)
                                        --------      --------       --------
  Results of operations before
     income taxes                          6,563         1,064         14,912
  Income tax (expense) recovery           (2,300)         (333)        (5,223)
                                        --------      --------       --------
  Results of operations after
     income taxes                       $  4,263      $    731       $  9,689
                                        ========      ========       ========

U.K.
  Revenue - net of royalties            $  3,582      $  4,411       $  6,231
  Production costs                          (338)         (964)        (1,064)
  Depletion and amortization              (9,304)       (3,646)        (3,319)
                                        --------      --------       --------
  Results of operations before
     income taxes                         (6,060)         (199)         1,848
  Income tax (expense) recovery            2,624           117           (787)
                                        --------      --------       --------
  Results of operations after
     income taxes                       $ (3,436)     $    (82)      $  1,061
                                        ========      ========       ========

Libya
  Revenue - net of royalties            $    297      $  1,005       $    169
  Production costs                           631        (1,041)           (38)
  Depletion and amortization             (11,393)       (5,144)          (131)
                                        --------      --------       --------
  Results of operations before
     income taxes                        (11,727)       (5,180)            --
  Income tax (expense) recovery            5,233         2,312             --
                                        --------      --------       --------
  Results of operations after
     income taxes                       $ (6,494)     $ (2,868)      $     --
                                        ========      ========       ========

Total
  Revenue - net of royalties            $ 75,366      $ 61,615       $ 69,627
  Production costs                       (19,097)      (17,680)       (16,003)
  Depletion and amortization             (67,493)      (48,250)       (36,864)
                                        --------      --------       --------
  Results of operations before
     income taxes                        (11,224)       (4,315)        16,760
  Income tax (expense) recovery            5,557         2,096         (6,010)
                                        --------      --------       --------
  Results of operations after
     income taxes                       $ (5,667)     $ (2,219)      $ 10,750
                                        ========      ========       ========
</TABLE>


                                       49
<PAGE>   52


(Unaudited)

CAPITALIZED COSTS RELATING TO GAS AND OIL EXPLORATION AND PRODUCTION ACTIVITIES

<TABLE>
<CAPTION>
December 31,                         1999         1998          1997
------------                       ---------    ---------    ---------
                                              (in thousands)

<S>                                <C>          <C>          <C>
Proved gas and oil properties      $ 550,097    $ 475,902    $ 402,885
Unproved gas and oil properties       57,304       76,478       56,922
                                   ---------    ---------    ---------
                                     607,401      552,380      459,807
Accumulated depletion               (339,786)    (266,066)    (224,154)
                                   ---------    ---------    ---------
Net capitalized costs              $ 267,615    $ 286,314    $ 235,653
                                   =========    =========    =========
</TABLE>


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

<TABLE>
<CAPTION>
Year ended December 31,                        1999          1998         1997
-----------------------                      --------      --------     --------
                                                        (in thousands)

<S>                                          <C>           <C>          <C>
Property acquisition costs:  U.S.            $  5,352      $  7,903     $  9,164
                             U.K.                  28           115          137
                                             --------      --------     --------
                                                5,380         8,018        9,301
                                             --------      --------     --------
Purchase of producing properties: U.S.             --           883           --
                                             --------      --------     --------
Sale of producing properties: U.S.               (155)           --           --
                                             --------      --------     --------
Exploration costs: U.S.                        28,753        43,317       35,540
                   U.K.                             9            72          115
                   Other foreign                1,531           606        1,207
                                             --------      --------     --------
                                               30,293        43,995       36,862
                                             --------      --------     --------
Development costs: U.S.                        19,542        39,606       23,260
                   U.K.                           (39)           71           30
                                             --------      --------     --------
                                               19,503        39,677       23,290
                                             --------      --------     --------
                                             $ 55,021      $ 92,573     $ 69,453
                                             ========      ========     ========
</TABLE>

         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.

                                       50
<PAGE>   53
(Unaudited)
<TABLE>
<CAPTION>
          December 31,                                         1999           1998           1997
          ------------                                       --------       --------       --------
                                                                         (in thousands)
<S>                                                          <C>            <C>            <C>
          U.S.
             Future cash inflows                             $665,306       $382,771       $480,669
             Future production costs                         (180,948)      (116,976)      (121,380)
             Future development costs                         (83,476)       (60,203)       (57,208)
             Future income tax expense                        (63,590)            --        (46,742)
                                                             --------       --------       --------
             Future net cash flows                            337,292        205,592        255,339
             Ten percent annual discount for
                estimated timing of cash flows               (114,871)       (62,089)       (70,844)
                                                             --------       --------       --------
             Standardized measure of
                discounted future net cash flows              222,421        143,503        184,495
                                                             --------       --------       --------
          U.K.
             Future cash inflows                               11,826         19,349         32,774
             Future production costs                           (8,261)        (7,483)        (5,734)
             Future development costs                          (1,397)        (1,457)        (1,450)
             Future income tax expense                             --             --         (6,340)
                                                             --------       --------       --------
             Future net cash flows                              2,168         10,409         19,250
             Ten percent annual discount for
                estimated timing of cash flows                    (56)        (1,404)        (4,172)
                                                             --------       --------       --------
             Standardized measure of
                discounted future net cash flows                2,112          9,005         15,078
                                                             --------       --------       --------
          Total
             Future cash inflows                              677,132        402,120        513,443
             Future production costs                         (189,209)      (124,459)      (127,114)
             Future development costs                         (84,873)       (61,660)       (58,658)
             Future income tax expense                        (63,590)            --        (53,082)
                                                             --------       --------       --------
             Future net cash flows                            339,460        216,001        274,589
             Ten percent annual discount for
                estimated timing of cash flows               (114,927)       (63,493)       (75,016)
                                                             --------       --------       --------
             Standardized measure of
                discounted future net cash flows             $224,533       $152,508       $199,573
                                                             ========       ========       ========
</TABLE>



                                       51


<PAGE>   54


(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,                                       1999                 1998               1997
----------------------                                        ----                 ----               ----
                                                                             (in thousands)
<S>                                                        <C>                  <C>                  <C>
Sales of oil, ngls and natural gas
     produced, net of production costs                     $(61,192)             $(45,231)           $(56,061)
Net change in prices and production costs                    83,559               (79,471)            (73,047)
Extensions and discoveries, less related costs               83,248                30,159              28,219
Purchase of producing properties                                 --                 2,793                  --
Sales of producing properties                                    --                    --                  --
Development costs incurred during the period                  9,734                23,131              10,096
Revisions of previous quantity estimates                     (8,441)              (17,191)             22,388
Accretion of discount                                        15,251                19,958              23,902
Net change in income taxes                                  (41,941)               38,739              26,534
Changes in estimated future development costs               (23,126)              (16,421)            (12,551)
Other                                                        14,933                (3,531)             (8,930)
                                                           --------              --------            --------
Net increase (decrease)                                      72,025               (47,065)            (39,450)
Beginning of year                                           152,508               199,573             239,023
                                                           --------              --------            --------
End of year                                                $224,533              $152,508            $199,573
                                                           ========              ========            ========
</TABLE>


                                       52

<PAGE>   55

          (Unaudited)

          QUARTERLY INFORMATION

<TABLE>
<CAPTION>
                                              1999 QUARTER ENDED                        1998 QUARTER ENDED
                                   MAR 31     JUN 30     SEP 30    DEC 31     MAR 31    JUN 30     SEP 30     DEC 31
                                  --------   --------   --------  --------   --------  --------   --------   --------
<S>                               <C>        <C>          <C>     <C>        <C>       <C>        <C>        <C>
FINANCIAL DATA
     Revenue(000's)               $ 13,218   $ 17,543   $ 22,763  $ 22,923   $ 18,718  $ 14,804   $ 13,943   $ 16,926

     Gross Profit (000's)           (4,169)   (12,491)     3,874       266      2,884      (342)    (1,345)    (6,719)
     Income (loss) (000's)          (3,860)    (8,507)     1,282      (754)       556    (1,735)    (2,472)    (5,404)
          Per common share           (0.29)     (0.64)      0.10     (0.03)      0.04     (0.13)     (0.18)     (0.40)

     Capital expenditures(000's)  $ 10,385   $  9,317   $ 16,485  $ 18,834   $ 24,015  $ 19,611   $ 22,572   $ 26,375

COMMON SHARE INFORMATION

     American Stock Exchange
          High                    $  15.50   $  18.63   $  22.75  $  20.38   $  24.75  $  24.75   $  23.75   $  20.25
          Low                         9.56      12.25      17.44     14.06      17.94     20.25      13.94      14.38
          Close                   $  12.25   $  17.50   $  19.00  $  17.25   $  23.75  $  23.69   $  17.06   $  14.38
          Volume (000's)             3,703      2,959      1,872     5,551      2,383     1,897      3,297      2,213

     Toronto Stock Exchange
          High                    C$ 24.00   C$ 26.95   C$ 34.00  C$ 30.25   C$ 35.25  C$ 35.35   C$ 34.75   C$ 30.70
          Low                        14.50      19.25      25.90     21.00      25.60     30.10      21.60      22.75
          Close                   C$ 18.90   C$ 25.25   C$ 27.60  C$ 25.00   C$ 34.05  C$ 34.40   C$ 25.70   C$ 23.05
          Volume(000's)                911        720        413       345        525       266      1,158      1,066
</TABLE>




                                       53

<PAGE>   56
(Unaudited)

<TABLE>
<CAPTION>
                                                    1999 QUARTER ENDED                             1998 QUARTER ENDED
                                         MAR 31     JUN 30      SEP 30      DEC 31      MAR 31      JUN 30      SEP 30     DEC 31
                                       ---------   ---------   ---------   ---------   ---------   ---------   ---------  ---------
<S>                                    <C>         <C>         <C>         <C>         <C>         <C>         <C>        <C>
PRODUCTION DATA
     Daily volumes, before royalties
          Natural gas (mmcf)
               U.S                          76.1        74.4        76.7        74.6        67.7        72.0        72.2       83.3
               U.K                          11.0         7.7        10.5        10.1        15.3         6.6         1.8       10.3
                                       ---------   ---------   ---------   ---------   ---------   ---------   ---------  ---------
               Total                        87.1        82.1        87.2        84.7        83.0        78.6        74.0       93.6
                                       =========   =========   =========   =========   =========   =========   =========  =========

          Oil and ngls (bbls)              3,679       5,222       5,200       4,329       3,269       3,495       3,261      3,899
          Equivalent (mmcfe)               109.2       113.4       118.4       110.7       102.7        99.5        93.6      117.0

     Daily volumes, after royalties
          Natural gas (mmcf)
               U.S                          60.1        59.1        61.4        59.8        53.9        57.1        57.4       66.2
               U.K                          11.0         7.7        10.5        10.1        15.3         6.6         1.8       10.3
                                       ---------   ---------   ---------   ---------   ---------   ---------   ---------  ---------
               Total                        71.1        66.8        71.9        69.9        69.2        63.7        59.2       76.5
                                       =========   =========   =========   =========   =========   =========   =========  =========

          Oil and ngls (bbls)              3,156       4,421       4,394       3,671       2,857       3,022       2,823      3,344
          Equivalent (mmcfe)                90.1        93.3        98.3        92.0        86.3        81.8        76.2       96.5

     Pricing
          Natural gas ($/mcf)
               U.S                     $    1.60   $    1.97   $    2.46   $    2.58   $    2.24   $    2.07   $    1.97  $    1.99
               U.K                          1.13        0.82        0.81        1.03        1.55        0.81        1.19       1.55
               Composite                    1.54        1.86        2.26        2.39        2.12        1.96        1.96       1.94
          Oil and ngls ($/bbl)         $   10.94   $   15.17   $   19.31   $   21.67   $   13.84   $   11.54   $   11.86  $   10.11
</TABLE>


                                       54
<PAGE>   57
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 date
March 15, 2000 for the annual meeting of shareholders on May 25, 2000.

ITEM 11. EXECUTIVE COMPENSATION

"Executive Compensation" on pages 5 to 9 of the Company's Information Circular
dated March 15, 2000 for the annual meeting of shareholders on May 25, 2000 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 15, 2000 for the annual meeting of shareholders
on May 25, 2000 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 29 of this report.

EXHIBITS

Reference is made to the Index to Exhibits on page 56 on this report.




                                       55
<PAGE>   58

                                    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 15, 2000 relating to the Company's annual meeting of shareholders to be held
                       on May 25, 2000.
****** 22           Subsidiaries of the Company.
 ***** 24 (a)       Consent of Netherland, Sewell & Associates, Inc.
 ***** 24 (b)       Consent of PricewaterhouseCoopers LLP.
 ***** 27           Financial Data Schedule

</TABLE>

     * 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.



                                       56
<PAGE>   59
                                   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
     -------------------------------------
     Stanley A. Milner, A.O.E., LL.D.
     President and Chief Executive Officer
     Principal Executive and Financial Officer


Dated:   March 15, 2000

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.

    /s/ D.E. MITCHELL            Director                        March 15, 2000
------------------------------
    D.E. Mitchell O.C.


     /s/ S.A. MILNER             President, Chief Executive      March 15, 2000
------------------------------   Officer and Director;
    S.A. Milner, A.O.E., LL.D.   Principal Executive and
                                 Financial Officer

     /s/ S.C. HURLEY             Director                        March 15, 2000
------------------------------
       S.C. Hurley


     /s/ H.J. KELLY              Director                        March 15, 2000
------------------------------
       H.J. Kelly


     /s/ J.E. MAYBIN             Director                        March 15, 2000
------------------------------
       J.E. Maybin


    /s/ L.G. MUNIN               Director                        March 15, 2000
------------------------------
      L.G. Munin


    /s/ E.S. ONDRACK             Director                        March 15, 2000
------------------------------
      E.S. Ondrack


    /s/ S.T. PEELER              Director                        March 15, 2000
------------------------------
      S.T. Peeler


    /s/ R.J. STEFURE             Vice President and              March 15, 2000
------------------------------   Controller Principal
      R.J. Stefure               Accounting Officer


                                       57
<PAGE>   60


                               INDEX TO EXHIBITS

      <TABLE>
      <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 15, 2000 relating to the Company's annual meeting of shareholders to be held
                       on May 25, 2000.
****** 22           Subsidiaries of the Company.
 ***** 24 (a)       Consent of Netherland, Sewell & Associates, Inc.
 ***** 24 (b)       Consent of PricewaterhouseCoopers LLP.
 ***** 27           Financial Data Schedule

</TABLE>

     * 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.