<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, 2000

Commission File number 1-10216:

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

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

<TABLE>
<CAPTION>
     1201 TD TOWER, 10088 - 102 AVENUE,
         EDMONTON, ALBERTA, CANADA                                            T5J 2Z1
---------------------------------------------               ---------------------------------------------
<S>                                                         <C>
     (Address of Registrant's principal                                    (Postal code)
             executive offices)
</TABLE>

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

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

<TABLE>
<CAPTION>
Title of each class                                         Name of each exchange on which registered
-------------------                                         -----------------------------------------
<S>                                                         <C>
Common Shares, no par value, of
     Chieftain International, Inc.                          American Stock Exchange
</TABLE>

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

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

The aggregate market value of the voting stock of Chieftain International, Inc.
held by non-affiliates of said registrant on March 14, 2001 was US$408,903,378.

The number of shares outstanding of the common stock of Chieftain International,
Inc. on March 14, 2001 was 16,034,477.



                       DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Chieftain International, Inc. Information Circular dated April
4, 2001 for its annual and special meeting of shareholders to be held on May 17,
2001, are incorporated by reference into Part III hereof, to the extent
indicated herein. The Exhibits Index can be found on page 55 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.
                          2000 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 .....................................................................       7
               Gas and Oil Capital Expenditures ............................................       7
               Drilling Activity ...........................................................       8
               Wells .......................................................................       8
               Reserves ....................................................................       8
               Production Volumes, Prices and Costs ........................................       9
               Employees ...................................................................       9
               Business Risks ..............................................................       9
               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 ...................................      30
    Item 9.  Changes in and Disagreements with Accountants on Accounting and Financial
             Disclosure.....................................................................      54

                                                PART III

    Item 10. Directors and Executive Officers ..............................................      54
    Item 11. Executive Compensation ........................................................      54
    Item 12. Security Ownership of Certain Beneficial Owners and Management ................      54
    Item 13. Certain Relationships and Related Transactions ................................      54

                                                PART IV

    Item 14. Exhibits and Reports on Form 8-K ..............................................      54

Signatures .................................................................................      56
</TABLE>

<PAGE>   3

                                     PART I


ITEM 1. BUSINESS

We are 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 offshore US Gulf of Mexico. We also have
properties located onshore in Louisiana, in the Four Corners area of southeast
Utah and in the UK 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 in April, 1989.

We have a large natural gas and oil lease acreage position in the US Gulf of
Mexico region. Our lease interests in the Gulf of Mexico region 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 natural gas and oil
reserves, to relatively lower risk development and exploitation projects with
lower reserve potential. Our exploration efforts are supported by an extensive
3D 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 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 141 lease blocks located on the continental shelf of the US
Gulf of Mexico. We also have interests in 11 deep-water blocks. Of these lease
blocks, 99 are held as exploratory acreage and 53 are held by production. We are
operator of 45 of these blocks. Our average working interest in our US Gulf of
Mexico leases is approximately 40%. In 2000 our production was 100.5 mmcfe per
day (82.9 mmcfe per day after royalties) of which 78%, or 78.8 mmcfe per day
(63.9 mmcfe per day after royalties), was in the US Gulf of Mexico.

In addition to our US Gulf of Mexico properties, we own various interests in two
large light oil producing units in the Four Corners area of southeast Utah where
our production averaged 1,793 barrels per day (1,566 barrels per day after
royalties) in 2000. We own an interest in approximately 8,300 net acres in the
UK sector of the North Sea where our production averaged 5.4 mmcfe per day
(before and after royalties) in 2000. We are also engaged in exploratory
activities onshore in Louisiana.

At December 31, 2000, we had estimated proved reserves of 326 bcfe (266 bcfe
after royalties). These reserves had a present value of net cash flows before
income taxes, discounted at 10%, of $1.2 billion using constant natural gas and
oil prices in effect on December 31, 2000, which averaged $9.68 per mcf for US
natural gas, $3.65 per mcf for UK natural gas and $24.60 per barrel for oil. At
December 31, 2000, approximately 72% of our proved reserves were natural gas and
approximately 59% of our proved reserves were developed. Our total proved
reserves at December 31, 2000 had a reserve life index of approximately 8.9
years.


SEGMENT INFORMATION

Reference is made to pages 42 and 43 hereof for financial information with
respect to our geographic segments for the years ended December 31, 2000, 1999
and 1998.


------------
* Unless the context indicates another meaning, the terms "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".

Our 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 in the US Gulf of Mexico and
onshore Louisiana, Utah and other parts of the US and in the UK 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, 2000. The estimated present
values reflect the US Securities and Exchange Commission required use of
year-end prices, which at December 31, 2000 were $9.68 per mcf for US natural
gas and $24.60 per barrel of oil.

<TABLE>
<CAPTION>
                               Proved reserves (before royalties)
                            ------------------------------------------
                                                                                  Estimated
                                                                            present value before
                              Natural        Oil and                          income taxes of
                               gas            ngls             Total          proved reserves
                              (mmcf)         (mbbls)          (mmcfe)        (US$ in thousands)
                            ----------      ----------      ----------      --------------------
<S>                         <C>             <C>             <C>             <C>
Gulf of Mexico                 154,404           4,808         183,252           $  904,082
Onshore Louisiana               71,858             229          73,232              262,126
Utah and Other Onshore           1,589          10,277          63,251               46,864
                               -------          ------         -------           ----------
   Total US                    227,851          15,314         319,735            1,213,072
UK (North Sea)                   5,985              19           6,099               13,887
                               -------          ------         -------           ----------
   Total                       233,836          15,333         325,834           $1,226,959
                               =======          ======         =======           ==========
</TABLE>

US GULF OF MEXICO

We concentrate our exploration and production activities in, and devote
substantial managerial and financial resources to, the offshore US 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. Our exploration and development activities are
focused primarily on 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 US Gulf of Mexico. With an average
interest of 40% in 152 blocks, we rank as one of the top ten independent
leaseholders in the US Gulf of Mexico. Of these lease blocks, 141 are shallow
water blocks and 11 are deep-water blocks. We acquired 11 blocks covering 55,696
acres at the March 2000 Central Gulf of Mexico lease sale. We acquired 3 blocks,
covering 17,280 acres, at the Western Gulf of Mexico lease sale in late August
2000. Our acreage in the Gulf of Mexico covered 719,798 (285,598 net) acres at
December 31, 2000. Of the 152 US Gulf of Mexico blocks in which we hold an
interest, we are the designated operator of 45.

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

        WESTERN GULF (OFFSHORE TEXAS)

MUSTANG ISLAND:

<TABLE>
<CAPTION>
Blocks  Gross Acres  Net Acres     Average Interest      Average 2000 Production       Average 2000 Production
------  -----------  ---------     ----------------   ----------------------------   ----------------------------
<S>     <C>          <C>           <C>                <C>                            <C>
                                                      (our share, before royalties)  (our share, after royalties)
  5       21,818      10,549            48.3%               7.7 mmcf per day               6.4 mmcf per day
</TABLE>

Most of our production in this area comes from our 50% working interest in Block
784. No significant exploration or development work is currently planned for
2001.


                                       2
<PAGE>   5

MATAGORDA ISLAND:

<TABLE>
<CAPTION>
Blocks  Gross Acres  Net Acres     Average Interest      Average 2000 Production       Average 2000 Production
------  -----------  ---------     ----------------   ----------------------------   ----------------------------
<S>     <C>          <C>           <C>                <C>                            <C>
                                                      (our share, before royalties)  (our share, after royalties)
  8       41,849      13,279            31.7%              8.1 mmcf per day                 6.4 mmcf per day
</TABLE>

In 2000, we participated in one successful exploratory well and one successful
development well on Block 704, in which we have a 25% working interest.
Production commenced from these wells late in the fourth quarter. Numerous
wireline, coiled tubing and rig recompletions are planned for the Matagorda
Island area during 2001. We also expect to drill an exploratory well on Block
634 where we have a 24.1% working interest.

HIGH ISLAND/EAST ADDITION/SOUTH EXTENSION:

<TABLE>
<CAPTION>
Blocks  Gross Acres  Net Acres     Average Interest      Average 2000 Production       Average 2000 Production
------  -----------  ---------     ----------------   ----------------------------   ----------------------------
<S>     <C>          <C>           <C>                <C>                            <C>
                                                      (our share, before royalties)  (our share, after royalties)
  13      74,880      29,378            39.2%              8.6 mmcf per day and          7.0 mmcf per day and
                                                            95 barrels per day            77 barrels per day
</TABLE>

During 2000, we participated in two unsuccessful exploratory wells in this area,
both on Block 206. We had a 33.3% working interest in one well and a 25% working
interest in the other. In 2001, we expect to participate in an exploratory well
on each of Block 163, where we have a 30% working interest, Block 166, where we
have a 33.3% working interest, and Block 348, where we have a 33.3% working
interest.

HIGH ISLAND SOUTH ADDITION:

<TABLE>
<CAPTION>
Blocks  Gross Acres  Net Acres     Average Interest      Average 2000 Production       Average 2000 Production
------  -----------  ---------     ----------------   ----------------------------   ----------------------------
<S>     <C>          <C>           <C>                <C>                            <C>
                                                      (our share, before royalties)  (our share, after royalties)
  12      64,800      33,821            52.2%                0.6 mmcf per day               0.5 mmcf per day
</TABLE>

During 2000, we participated in two successful exploratory wells, one successful
development well and one unsuccessful exploratory well in this area. Late in the
fourth quarter, a successful exploratory well was drilled from an existing
production facility on Block A-467, where we have a 50% working interest.
Production commenced in the first quarter of 2001. An exploratory well on Block
A-554, where we have a 41.7% working interest, was drilled successfully in the
fourth quarter and this natural gas discovery is expected to commence production
during 2001. We are operator of Block A-531 where a development well encountered
a commercial natural gas reservoir. The A-531Block, in which we have a 50%
working interest, is expected to commence production during 2001 through a
facility on the adjoining Block A-510, which we also operate and have a 50%
working interest in. An exploratory well on Block A-567, where we have a 50%
working interest, was junked and abandoned prior to reaching its geological
objective and the drilling contractor did not earn there turnkey contract fee.
In the second half of 2001, we expect to drill an exploratory well on Block
A-567.

GARDEN BANKS:

<TABLE>
<CAPTION>
Blocks  Gross Acres  Net Acres     Average Interest      Average 2000 Production       Average 2000 Production
------  -----------  ---------     ----------------   ----------------------------   ----------------------------
<S>     <C>          <C>           <C>                <C>                            <C>
                                                      (our share, before royalties)  (our share, after royalties)
  4       23,040       7,200            31.3%               2.8 mmcf per day                2.4 mmcf per day
</TABLE>

All of our production in this area currently comes from our 25% working interest
in Block 224. We will be participating in an exploratory well in this deep water
area during 2001. With a planned target depth of approximately 18,000 feet, the
well could be drilled as early as the second quarter of 2001. It will test the
Antigua prospect, located on Blocks 397 and 441. The water depth in the drilling
area is approximately 2,500 feet. We have a 25% working interest in the project.

                                       3
<PAGE>   6

     CENTRAL GULF (OFFSHORE LOUISIANA)

EAST CAMERON:

<TABLE>
<CAPTION>
Blocks  Gross Acres  Net Acres     Average Interest      Average 2000 Production       Average 2000 Production
------  -----------  ---------     ----------------   ----------------------------   ----------------------------
<S>     <C>          <C>           <C>                <C>                            <C>
                                                      (our share, before royalties)  (our share, after royalties)
  7       32,500      11,250            34.6%              2.2 mmcf per day and            1.8 mmcf per day and
                                                            284 barrels per day            236 barrels per day
</TABLE>

In 2000, we participated in three successful exploratory wells in this area.
Late in the fourth quarter, a natural gas well was drilled on Block 83, where we
have a 25% working interest. Two natural gas wells were drilled on Block 104,
where we have a 40% working interest. The Block 83 and Block 104 wells are
expected to commence production during 2001. An exploratory well on Block 255,
where we have a 60% working interest, and another on Block 369, where we have a
40% working interest, are planned for the second half and first half,
respectively, of 2001.

VERMILION:

<TABLE>
<CAPTION>
Blocks  Gross Acres  Net Acres     Average Interest      Average 2000 Production       Average 2000 Production
------  -----------  ---------     ----------------   ----------------------------   ----------------------------
<S>     <C>          <C>           <C>                <C>                            <C>
                                                      (our share, before royalties)  (our share, after royalties)
  5       15,267      7,908             51.8%             10.1 mmcf per day and          8.4 mmcf per day and
                                                           325 barrels per day            271 barrels per day
</TABLE>

During 2000, we participated in three exploratory wells in this area. Two
successful wells, drilled on Block 267 where we have a 60% working interest,
produce through a facility installed for a well drilled in 1999. A fourth
quarter well on Block 263, where we have a 33.3% interest, was unsuccessful.

An exploratory well on each of Block 16, where we have a 40% working interest,
Block 23, where we have a 25% working interest, and Block 72, where we have a
100% working interest, are planned for the second half of 2001.

SOUTH MARSH ISLAND:

<TABLE>
<CAPTION>
Blocks  Gross Acres  Net Acres     Average Interest      Average 2000 Production       Average 2000 Production
------  -----------  ---------     ----------------   ----------------------------   ----------------------------
<S>     <C>          <C>           <C>                <C>                            <C>
                                                      (our share, before royalties)  (our share, after royalties)
  6       27,852      18,926             68%              2.5 mmcf per day and           2.1 mmcf per day and
                                                           897 barrels per day            747 barrels per day
</TABLE>

In 2000, we participated in one exploratory well on Block 111, where we have a
25% working interest. The well did not find commercial reserves.

During 2001, we expect to participate in three exploratory wells, all of which
we will operate, and one development well. Two exploratory wells on Block 51,
where we have a 60% working interest, and one exploratory well on Block 139,
where we have a 100% working interest, will be drilled at approximately
mid-year. The development well will be drilled on Block 39, where we have a 50%
working interest.

EUGENE ISLAND:

<TABLE>
<CAPTION>
Blocks  Gross Acres  Net Acres     Average Interest      Average 2000 Production       Average 2000 Production
------  -----------  ---------     ----------------   ----------------------------   ----------------------------
<S>     <C>          <C>           <C>                <C>                            <C>
                                                      (our share, before royalties)  (our share, after royalties)
  7       31,250      10,417           33.3%                      --                                --
</TABLE>

In 2000, our partner in Block 189 exchanged a 25% working interest for a 4%
overriding royalty, bringing our working interest to 100%. A development well,
which we began drilling early in 2001, if successful, will be produced along
with two successful wells drilled previously from production facilities
installed late in the fourth quarter of 2000. Production is expected to commence
in 2001. In mid-2001, an exploratory well is planned for Block 355 where we have
a 33.3% working interest.

                                       4
<PAGE>   7

SOUTH TIMBALIER:

<TABLE>
<CAPTION>
Blocks  Gross Acres  Net Acres     Average Interest      Average 2000 Production       Average 2000 Production
------  -----------  ---------     ----------------   ----------------------------   ----------------------------
<S>     <C>          <C>           <C>                <C>                            <C>
                                                      (our share, before royalties)  (our share, after royalties)
  8        36,561     16,030           43.8%                0.9 mmcf per day                 0.7 mmcf per day
</TABLE>

In 2000, we participated in two exploratory wells in this area. A successful
natural gas well was drilled on Block 250, where we have a 50% working interest,
and production is expected to commence during 2001. Late in the year, a well
drilled on Block 251, where we have a 50% working interest, did not find
commercial reserves.

WEST CAMERON:

<TABLE>
<CAPTION>
Blocks  Gross Acres  Net Acres     Average Interest      Average 2000 Production       Average 2000 Production
------  -----------  ---------     ----------------   ----------------------------   ----------------------------
<S>     <C>          <C>           <C>                <C>                            <C>
                                                      (our share, before royalties)  (our share, after royalties)
  11       49,410     17,159            34.7%               2.6 mmcf per day                 2.2 mmcf per day
</TABLE>

In 2000, we participated in nine exploratory wells in this area, seven of which
were successful. In the fourth quarter, a successful well on Block 192, where we
have a 25% working interest, was drilled from an existing production facility
and production began before year-end. We operate Block 300, where we have a 35%
working interest, and where one of two wells drilled was successful. Block 300
commenced production in the fourth quarter. During the second half of the year,
four successful natural gas wells were drilled on Block 370, where we have a 40%
working interest. The Block 370 wells are expected to commence production during
2001. On Block 614, where we have a 25% working interest, a successful natural
gas well was drilled and began producing late in the year along with the 1999
discovery on Block 613. On Block 386, where we have an 80% working interest, a
second quarter well did not find commercial reserves.

During 2001, we expect to participate in four exploratory wells, three of which
we will operate, and three development wells. We will operate an exploratory
well on each of Block 135 and Block 497, where we have 50% working interests. An
exploratory well and two development wells will be drilled on Block 192, where
we have a 25% working interest. A successful exploratory well was drilled in the
first quarter of 2001, and a development well will be drilled in the second half
of 2001, on Block 300, where we have a 35% working interest. The 2001 Block 300
exploratory well is expected to commence production in mid-2000.

MAIN PASS:

<TABLE>
<CAPTION>
Blocks  Gross Acres  Net Acres     Average Interest      Average 2000 Production       Average 2000 Production
------  -----------  ---------     ----------------   ----------------------------   ----------------------------
<S>     <C>          <C>           <C>                <C>                            <C>
                                                      (our share, before royalties)  (our share, after royalties)
   6       21,695      2,453            11.3%             11.3 mmcf per day and            8.8 mmcf per day and
                                                           274 barrels per day              210 barrels per day
</TABLE>

In 2000, the Main Pass area continued to be one of the most significant
contributors to our natural gas production. One development well on Block 223,
where we have a 10% working interest, is currently planned for 2001.

MISSISSIPPI CANYON:

<TABLE>
<CAPTION>
Blocks  Gross Acres  Net Acres     Average Interest      Average 2000 Production       Average 2000 Production
------  -----------  ---------     ----------------   ----------------------------   ----------------------------
<S>     <C>          <C>           <C>                <C>                            <C>
                                                      (our share, before royalties)  (our share, after royalties)
  4        23,040     7,104            30.1%               0.04 mmcf per day               0.04 mmcf per day
</TABLE>

We will participate in two exploratory wells in this deep-water area during
2001. The first well is planned for the west half of Block 29, where we have a
27% working interest. It will test the Schellhorn prospect at a planned target
depth of approximately 10,000 to 12,500 feet in a water depth of approximately
2,000 feet. Drilling operations will utilize BP's Pompano subsea template.
Should the well be successful, we expect to be able to complete it for
production in 2001. The other exploratory well, with a planned depth of
approximately 15,000 feet, will be drilled on Block 489, where we will have a
20% working interest. Drilling is expected to commence mid- year in a water
depth of approximately 1,900 feet.


                                       5
<PAGE>   8

VERMILION PARISH, LOUISIANA

NORTHEAST WRIGHT:

<TABLE>
<CAPTION>
Gross Acres  Net Acres     Average Interest      Average 2000 Production       Average 2000 Production
-----------  ---------     ----------------   ----------------------------   ----------------------------
<S>          <C>           <C>                <C>                            <C>
                                              (our share, before royalties)  (our share, after royalties)
  3,709       1,852            49.9%                3.9 mmcf per day                2.9 mmcf per day
</TABLE>

During 2000, we participated in one successful exploratory well and one
successful development well in the Northeast Wright Field. Both the Langlinais
#1 development well, in which we have a 50% working interest, and the
Delahoussaye #2 exploratory well, in which we have a 1.8% working interest,
commenced production during the summer of 2000.

We expect to begin the drilling of a development well, Trahan #1, during the
second half of 2001.


FOUR CORNERS (PARADOX BASIN) AREA, UTAH

ANETH UNIT:

<TABLE>
<CAPTION>
Gross Acres  Net Acres     Unit Interest         Average 2000 Production       Average 2000 Production
-----------  ---------     -------------      ----------------------------   ----------------------------
<S>          <C>           <C>                <C>                            <C>
                                              (our share, before royalties)  (our share, after royalties)
  18,070       3,066            13.4%             0.15 mmcf per day and         0.13 mmcf per day and
                                                   644 barrels per day           560 barrels per day
</TABLE>

RATHERFORD UNIT:

<TABLE>
<CAPTION>
Gross Acres  Net Acres     Unit Interest         Average 2000 Production       Average 2000 Production
-----------  ---------     -------------      ----------------------------   ----------------------------
<S>          <C>           <C>                <C>                            <C>
                                              (our share, before royalties)  (our share, after royalties)
  12,910      2,560             21.4%             0.35 mmcf per day and          0.31 mmcf per day and
                                                  1,149 barrels per day          1,006 barrels per day
</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 project in the
Ratherford Unit is under consideration for late 2001.


NORTH SEA - UNITED KINGDOM SECTOR

<TABLE>
<CAPTION>
Gross Acres  Net Acres     Unit Interest         Average 2000 Production       Average 2000 Production
-----------  ---------     -------------      ----------------------------   ----------------------------
<S>          <C>           <C>                <C>                            <C>
                                              (our share, before royalties)  (our share, after royalties)
  46,553      8,272             17.8%              5.3 mmcf per day and           5.3 mmcf per day and
                                                    21 barrels per day             21 barrels per day
</TABLE>

All of our UK production comes from our interests in the Galahad Field, where we
have a 17.8% working interest, and in the Mordred Field, where we have a 5.3%
working interest. It is sold under 30-day contracts and in 2000 obtained an
average price of $1.96 per mcf, net of transportation costs. The UK production
is royalty free. Seismic work is planned to evaluate exploration ideas on our
acreage in 2001.

                                       6
<PAGE>   9


ACREAGE

The following table summarizes the developed and undeveloped acreage held by us
as at December 31, 2000. Where applicable, interests which are not working
interests (none of which is material) have been converted to working interest
equivalents.

<TABLE>
<CAPTION>
                                        Developed Acres           Undeveloped Acres
                                      --------------------      --------------------
Area                                   Gross         Net         Gross         Net
--------------------------------      -------      -------      -------      -------
<S>                                   <C>          <C>          <C>          <C>
United States
   Offshore Gulf of Mexico
     Louisiana                         21,419        6,867      323,090      120,024
     Texas                             13,942        4,161      356,175      153,056
     Texas State                          300           22        4,872        1,468
                                       ------       ------      -------      -------
   Total Offshore Gulf of Mexico       35,661       11,050      684,137      274,548
                                       ======       ======      =======      =======

   Onshore
     Louisiana                          2,691        1,346        1,867          930
     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                       33,872        6,503        7,347        5,090
                                       ======       ======      =======      =======
Total United States                    69,533       17,553      691,484      279,638
                                       ======       ======      =======      =======
United Kingdom
   North Sea                            7,584        1,348       38,969        6,924
                                       ------       ------      -------      -------
Total, all areas                       77,117       18,901      730,453      286,562
                                       ======       ======      =======      =======
</TABLE>

Our developed and undeveloped acreage in all areas covered 807,570 (305,463 net)
acres at December 31, 2000.

The undeveloped acreage, which has a cost to us of approximately $37 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, 2000, 1999 and
1998.

                                       7
<PAGE>   10


DRILLING ACTIVITY

The following table summarizes the results of our drilling activities during the
years ended December 31, 2000, 1999 and 1998.

<TABLE>
<CAPTION>
EXPLORATORY WELLS - Year ended December 31,             2000                  1999                  1998
------------------------------------------------------------------      ----------------      ----------------
                                                  GROSS       NET       Gross       Net       Gross       Net
                                                  -----      -----      -----      -----      -----      -----
<S>                                               <C>        <C>        <C>        <C>        <C>        <C>
Gas                                                  19       7.13          4       2.10          5       1.89
Oil                                                  --         --         --         --          1       0.33
Oil/Gas                                              --         --          4       2.00         --         --
Evaluating                                           --         --          1       0.50         --         --
Drilling at end of year                               1       0.67          3       0.62         --         --
Abandoned                                            13       4.80          5       1.45          8       3.45
                                                     --      -----         --       ----         --       ----
                                                     33      12.60         17       6.67         14       5.67
                                                     ==      =====         ==       ====         ==       ====
</TABLE>

<TABLE>
<CAPTION>
DEVELOPMENT WELLS - Year ended December 31,            2000                1999                1998
----------------------------------------------------------------     ---------------      --------------
                                                  GROSS     NET      Gross      Net       Gross     Net
                                                  -----     ----     -----      ----      -----     ----
<S>                                               <C>       <C>      <C>        <C>       <C>       <C>
Gas                                                  3      1.25         5      0.77         4      0.32
Oil                                                 --        --        --        --        30      6.01
Oil/Gas                                             --        --         1      0.50         1      0.25
Evaluating                                          --        --        --        --        --        --
Drilling at end of year                             --        --        --        --        --        --
Abandoned                                           --        --         1      0.50        --        --
                                                    --      ----        --      ----        --      ----
                                                     3      1.25         7      1.77        35      6.58
                                                    ==      ====        ==      ====        ==      ====
</TABLE>

WELLS

Our productive gas and oil wells as at December 31, 2000 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                      --         --        263      43.56
Louisiana                  6       2.52         --         --
US Gulf of Mexico         95      20.61         20       6.59
United Kingdom             3       0.41         --         --
                         ---      -----        ---      -----
                         109      24.47        285      50.62
                         ===      =====        ===      =====
</TABLE>

RESERVES

Our US natural gas and oil reserves have been evaluated by Netherland, Sewell &
Associates, Inc. ("NS&A") and we have evaluated our UK reserves which amount to
1.9% (2.3% after royalties) of total equivalent reserves.

For estimates of our proved and proved developed reserves see "Supplementary
Financial Information".




                                       8
<PAGE>   11

PRODUCTION VOLUMES, PRICES AND COSTS

Our net production of gas and oil (computed after royalty deductions but before
production taxes) for the years ended December 31, 2000, 1999 and 1998 is listed
below. Also listed are average sales prices and average production costs during
such periods.

<TABLE>
<CAPTION>
Year ended December 31,                 2000            1999            1998
-------------------------------      ----------      ----------      ----------
<S>                                  <C>             <C>             <C>
Total Net Production:
   Natural gas (mmcf)                    22,871          25,533          24,504
   Oil and liquids (mbbls)                1,243           1,428           1,100
   Gas equivalent (mmcfe)                30,329          34,103          31,102

Average Daily Net Production:
   Natural gas (mmcf)                      62.5            70.0            67.1
   Oil and liquids (barrels)*             3,396           3,913           3,012
   Gas equivalent (mmcfe)                  82.9            93.4            85.2

Average Sales Price:
   Natural gas (per mcf)             $     3.63      $     2.02      $     1.99
   Oil and liquids (per barrel)      $    27.72      $    17.05      $    11.74

Average Production Cost:
   Natural gas (per mcf)             $     0.23      $     0.21      $     0.30
   Oil and liquids (per barrel)      $     5.17      $     4.60      $     5.78
</TABLE>
---------------

* Oil comprised approximately 82% (1999 - 89%; 1998 - 82%) of our oil and
  liquids production.

EMPLOYEES

At December 31, 2000, we had 44 full-time equivalent employees. In addition, we
engage 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 US 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.

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 US Gulf of Mexico (offshore Texas and
Louisiana), we may pursue acquisitions or properties located in other geographic
areas, which would decrease our geographic concentration.



                                       9
<PAGE>   12


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, 2000, approximately 41% 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 workers' 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.

Compliance with governmental regulations is costly and complex, especially
regulations relating to environmental protection.

Our US 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.

US 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 UK, 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.

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:

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

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

BLOCK refers to an offshore US Gulf of Mexico natural 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.

GROSS ACRES means the total number of acres in which we own an interest.

GROSS WELLS means the total number of wells in which we own an interest.

LIQUIDS means natural gas liquids.

MBBLS means 1,000 barrels.

MCF means 1,000 cubic feet.

MMCF means 1,000,000 cubic feet.

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

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 barrel of oil and liquids.

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 natural
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 us 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 our
materially important physical properties. In addition, we lease 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 our security holders during the fourth
quarter of 2000.


EXECUTIVE OFFICERS OF THE REGISTRANT

The following table lists the name and age of each Executive Officer and all
positions and offices held with us 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 17, 2001.

<TABLE>
<CAPTION>
NAME                    AGE       POSITION/OFFICE
----                    ---       ---------------
<S>                     <C>       <C>
Stanley A. Milner       72        Director, President and Chief Executive Officer
Stephen C. Hurley       51        Director, Senior Vice President and Chief Operating Officer
Esther S. Ondrack       60        Director, Senior Vice President and Secretary
S. Jay Milner           43        Vice President, Drilling and Production
Ronald J. Stefure       53        Vice President and Controller
Randall P. Boyd         44        Vice President, Investor Relations
</TABLE>

With the following exceptions, all of the officers have held their positions as
officers since our incorporation in 1988, such position being his or her
principal occupation. S.C. Hurley joined us in September, 1995 prior to which
time he was the Vice President, Exploration of a US based integrated oil
company. S.J. Milner and R.J. Stefure were appointed officers in June, 1995 and
prior thereto held management positions with us. R.P. Boyd joined us in 1999
prior to which time he was Chief Financial Officer 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 our Common Shares are traded is the
American Stock Exchange. The Common Shares are also traded on the Toronto Stock
Exchange. The high and low prices of our Common Shares (the "Common Shares")
during each quarter since December 31, 1998 are shown below.

<TABLE>
<CAPTION>
                                    Price History of Chieftain
                                 International, Inc. Common Shares
                         --------------------------------------------------
                         American Stock Exchange     Toronto Stock Exchange
                             (US dollars)               (Cdn. dollars)
                         ----------------------      ----------------------
                           High           Low          High          Low
                         --------      --------      --------      --------
<S>                      <C>           <C>           <C>           <C>
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
   First quarter            20.38         13.38         27.85         19.50
   Second quarter           22.25         17.63         33.20         25.45
   Third quarter            22.50         15.88         33.50         23.60
   Fourth quarter           27.75         19.31         41.90         29.20

2001
   January                  27.75         22.25         41.50         33.45
   February                 25.16         22.02         38.90         34.00
   March 1 to March 14      45.50         34.20         29.65         22.00
</TABLE>

The Common Shares were held by 116 Shareholders of record on December 31, 2000.
We estimate that investment dealers and other nominees hold Common Shares for
approximately 2,200 beneficial holders.

At the present time it is not our 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 our earnings and our 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, 2000 has been derived from our consolidated financial
statements 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,                               2000           1999            1998            1997           1996
--------------------------------------------------  ---------      ---------       ---------       ---------      ---------
                                                          (in thousands except per share amounts and  operating data)
<S>                                                 <C>            <C>             <C>             <C>            <C>
INCOME STATEMENT DATA:
Revenue                                             $ 119,873      $  76,447       $  64,391       $  72,055      $  63,099
Production costs                                       14,092         14,320          16,355          13,325         12,220
General and administrative expenses                     5,984          4,580           4,796           4,308          3,972
Interest                                                1,131          2,496             437              --             --
Depletion and amortization(1)                          43,770         51,385          42,081          36,951         30,920
Additional depletion(2)                                    --         16,186           6,244              --             --
Write-down of marketable securities                     1,079             --              --              --             --
Income (loss) from operations, before dividends
   on preferred shares of a subsidiary                 32,290         (6,897)         (4,113)         10,160          9,784
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)       27,348        (11,839)         (9,055)          5,218          4,842

Net income (loss) per common share:(1)
   Basic                                                 1.69          (0.86)          (0.67)           0.38           0.37
   Diluted                                               1.64          (0.86)          (0.67)           0.38           0.36
Weighted average number of common shares outstanding   16,183         13,701          13,480          13,621         13,065

OTHER DATA:
Cash flow from operations                           $  93,631      $  50,098       $  37,847       $  49,473      $  41,841
Net natural gas and oil capital expenditures        $ 102,701      $  55,021       $  92,573       $  69,453      $  57,673

BALANCE SHEET DATA (at end of period):
Working capital                                     $   9,962      $  13,604       $   2,392       $  22,676      $  42,854
Total assets(1)                                     $ 395,460      $ 330,758       $ 318,584       $ 285,125      $ 267,442
Long-term debt                                      $  20,000      $  10,000       $  40,000       $      --      $      --
Shareholders' equity(1)                             $ 295,146      $ 271,101       $ 234,946       $ 249,466      $ 244,122

OPERATING DATA:
Average Daily Net Production:
   Natural gas (mmcf)                                    62.5           70.0            67.1            64.2           59.8
   Oil and liquids (barrels)                            3,396          3,913           3,012           2,261          2,005
   Natural gas equivalent (mmcfe)                        82.9           93.4            85.2            77.8           71.8
Average Sales Price:
   Natural gas (per mcf)                            $    3.63      $    2.02       $    1.99       $    2.33      $    2.09
   Oil and liquids (per barrel)                         27.72          17.05           11.74           18.94          20.99
Average Production Cost:
   Natural gas (per mcf)                            $    0.23      $    0.21       $    0.30       $    0.27      $    0.25
   Oil and liquids (per barrel)                          5.17           4.60            5.78            5.81           6.57
</TABLE>

                                       14
<PAGE>   17

Notes:

(1)     The use of US generally accepted accounting principles results in the
        following:

<TABLE>
<CAPTION>
Year ended December 31,                              2000           1999            1998            1997           1996
---------------------------------------------      ---------      ---------       ---------       ---------      ---------
                                                                      (in thousands except per share amounts)
<S>                                                <C>            <C>             <C>             <C>            <C>
Depletion and amortization                         $  32,728      $  33,762       $  37,846       $  33,774      $  28,539
Additional depletion                                      --         18,497          95,397              --             --
Net income (loss) applicable to common shares         35,733         (1,967)        (63,963)          7,510          6,202
Net income (loss) per common share:
  Basic                                                 2.21          (0.14)          (4.75)           0.55           0.47
  Diluted                                               2.06          (0.14)          (4.75)           0.54           0.46
Total assets                                         320,783        258,712         238,675         269,178        245,763
Shareholder's equity                                 183,775        151,345         105,318         174,746        167,110
</TABLE>

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

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
2000 audited consolidated financial statements. The information contains
forward-looking statements that are subject to risk factors associated with the
oil and gas business. Forward-looking statements typically contain words such as
"anticipate", "believe", "expect", "plan" or similar words suggesting future
outcomes. 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 and currency fluctuations, drilling and production results,
imprecision of reserve estimates, loss of market, industry competition,
environmental risks, political risks and capital restrictions.

Our financial statements and information are reported in US 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 US dollars. For a discussion of the effect
of differences in generally accepted accounting principles in Canada and the US
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 at the rate of one barrel of oil per six thousand cubic feet
of natural gas.


<TABLE>
<CAPTION>
Contents - Management's Discussion and Analysis
-----------------------------------------------
<S>                                                <C>
2000 Overview                                      15
Production                                         16
Natural Gas and Oil Marketing                      17
Revenue                                            17
Expenses                                           18
Net Income (Loss) Applicable to Common Shares      20
Capital Expenditures                               21
Finding and Development Costs                      22
Reserves                                           23
Capital Resources and Liquidity                    24
Risk Assessment                                    26
Corporate Governance                               27
Outlook and Prospects for Future Growth            28
</TABLE>


2000 OVERVIEW

Strong natural gas and oil prices contributed to our record financial results in
2000. Revenues were $145.3 million ($119.9 million after royalties), net income
applicable to common shares was $27.3 million, and cash flow from operations,
after preferred share dividends, was $93.6 million. These amounts compare to
revenues of $92.6 million ($76.4 million after royalties) in 1999 and $77.6
million ($64.4 million after royalties) in 1998, losses applicable to common
shares of $11.8 million in 1999 and $ 9.1 million in 1998 and cash flow from
operations of $50.1 million in 1999 and $37.8 million in 1998.

Basic net income per common share was $1.69 in 2000 compared to losses of $0.86
per share in 1999 and $0.67 per share in 1998.

                                       15
<PAGE>   18

Our average natural gas price was $3.63 per mcf in 2000 compared to $2.02 per
mcf in 1999 and $1.99 in 1998. Our combined average crude oil and ngls price was
$27.72 per barrel in 2000 compared to $17.05 in 1999 and $11.74 in 1998.

Net capital spending was $102.9 million in 2000 compared to $55.1 million in
1999 and $92.7 million in 1998. Three year finding and development costs for
proved reserves were $1.17 per mcfe ($1.50 per mcfe after royalties) in 2000
compared to $1.15 per mcfe ($1.45 per mcfe after royalties) in 1999 and $1.51
per mcfe ($1.89 per mcfe after royalties) in 1998.

We increased our proved reserves for the seventh consecutive year, adding 72.4
bcfe (56.2 bcfe after royalties), a reserve replacement rate of 197% (185% after
royalties). Total proved reserves increased to 326 bcfe (266 bcfe after
royalties).

At December 31, 2000, our proved reserves had a present value of future net cash
flows before income taxes, discounted at 10%, of $1.2 billion (1999 - $267
million; 1998 - $153 million). These values reflect the required use of year-end
prices, which at December 31, 2000 were $9.68 per mcf for US natural gas and
$24.60 per barrel of oil.

Production in 2000 averaged 100.5 mmcfe per day (82.9 mmcfe per day after
royalties) compared to 112.9 mmcfe per day (93.4 mmcfe per day after royalties)
in 1999 and 103.2 mmcfe per day (85.2 mmcfe per day after royalties) in 1998.
New production from eight properties was added during 2000, primarily during the
second half of the year. Production commenced from three of these properties in
December. As a result of this additional production, our exit rate at December
31, 2000 was 121.6 mmcfe per day (99.5 mmcfe per day after royalties).


PRODUCTION

<TABLE>
<CAPTION>
                                            Before royalties                        After royalties
                                    ---------------------------------      ---------------------------------
PRODUCTION SUMMARY                   2000         1999         1998         2000         1999         1998
------------------------------      -------      -------      -------      -------      -------      -------
<S>                                 <C>          <C>          <C>          <C>          <C>          <C>
Natural gas (mmcf per day)
   US                                  71.1         75.5         73.8         57.2         60.2         58.6
   UK                                   5.3          9.8          8.5          5.3          9.8          8.5
                                    -------      -------      -------      -------      -------      -------
   Total                               76.4         85.3         82.3         62.5         70.0         67.1
                                    =======      =======      =======      =======      ========     =======
Oil and ngls (barrels per day)        4,022        4,611        3,482        3,396        3,913        3,012
                                    =======      =======      =======      =======      =======      =======
Total natural gas equivalent
   (mmcfe per day)                    100.5        112.9        103.2         82.9         93.4         85.2
                                    =======      =======      =======      =======      =======      =======
Total annual equivalent (bcfe)         36.8         41.2         37.7         30.3         34.1         31.1
                                    =======      =======      =======      =======      =======      =======
</TABLE>

Our average combined natural gas and oil production rate decreased by 11% to
100.5 mmcfe per day (82.9 mmcfe per day after royalties) in 2000 from 112.9
mmcfe per day (93.4 mmcfe per day after royalties) in 1999 and 103.2 mmcfe per
day (85.2 mmcfe per day after royalties) in 1998. Natural gas comprised 76% (75%
after royalties) of our production volumes in both 2000 and 1999, and 80% (79%
after royalties) in 1998. In 2000, natural gas production was 28.0 bcf (22.9 bcf
after royalties) compared to 31.1 bcf (25.5 bcf after royalties) in 1999 and
30.0 bcf (24.5 bcf after royalties) in 1998. In 2000, oil and natural gas
liquids production was 1.5 mmbbls (1.2 mmbbls after royalties) compared to 1.7
mmbbls (1.4 mmbbls after royalties) in 1999 and 1.3 mmbbls (1.1 mmbbls after
royalties) in 1998.

Comparing 2000 and 1999, average production rates decreased 7.4 mmcfe per day
(5.5 mmcfe per day after royalties) in the US and 4.6 mmcfe per day (before and
after royalties) in the UK. During 2000, US production volumes decreased
compared to 1999 as a result of the concentration of production from new
properties in the second half of the year. The majority of the successful wells
drilled in 1999 and scheduled for development in 2000 experienced delays in both
follow-up drilling and facilities design and installation, causing a greater
than expected time lag in production additions. The decline in production was
halted in the second quarter, and production grew through the remainder of the
year. In the UK, where no further exploration and development is currently
planned, production is subject to normal decline.

Comparing 1999 and 1998, production growth was primarily from properties in the
US Gulf of Mexico region which produced for the first time in 1999.

Ninety-two percent of 2000 natural gas production came from our interests in 121
wells in the US Gulf of Mexico region compared to 88% (111 wells) in 1999 and
89% (108 wells) in 1998. Fifty-four percent of our 2000 and 1999 oil and ngls
production came from our holdings in the US Gulf of Mexico region (1998 - 28%).


                                       16
<PAGE>   19

NATURAL GAS AND OIL MARKETING

Ninety-six percent of our natural gas reserves are located in the US Gulf of
Mexico region where ready deliverability through numerous large capacity
pipelines and auxiliary feeder pipelines provides flexibility in marketing our
production. Natural gas prices in the US and in the UK are largely determined by
competitive market forces. Most of the natural gas produced by us, as well as
our US Gulf of Mexico region oil and natural gas liquids production, has been
marketed since 1989 by Highland Energy Company, an aggregator for several
natural gas producers.

Our 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 since
1989. Due to its quantity and quality, we have obtained premiums over locally
posted prices for this production.

Market prices of oil and natural gas fluctuate and can materially 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 price risk, we may
enter into forward sales 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, 2000, we had entered into forward sales for the physical
delivery, during the first nine months of 2001, of natural gas production
totaling 7.1 bcf (approximately 15% of our forecast 2001 equivalent volume), at
an average price, net of transportation, of $4.86 per mcf. At the 1999 year-end,
we had entered into forward sales for the physical delivery of 2000 natural gas
production of 6.1 bcf (approximately 17% of our 2000 equivalent volume) at an
average price of $2.49 per mcf. Forward sales of natural gas at December 31,
1998 were immaterial. Also at December 31, 1999, we had entered into oil forward
sales for the physical delivery of 90 mbbls of 2000 production at an average
price of $19.00 per barrel. We had not entered into oil forward sales at either
December 31, 2000 or 1998.

NATURAL GAS

Our composite average natural gas price was $3.63 per mcf in 2000 compared to
$2.02 in 1999 and $1.99 in 1998. The mild North American winter of 1998-1999 had
a downward effect on 1998 US natural gas prices. During the first quarter of
1999, we received an average of $1.54 per mcf for our US natural gas.
Thereafter, prices increased to an average of $2.39 per mcf in the fourth
quarter of 1999. Strong demand for electricity, as well as the demand associated
with replenishing storage for the forthcoming 2000-2001 winter, pulled our US
natural gas price from $2.51 per mcf in the first quarter of 2000 to $3.18 per
mcf and $3.84 per mcf in the second and third quarters, respectively. During the
fourth quarter of 2000, the benchmark New York Mercantile Exchange natural gas
futures experienced significant volatility. This is reflected in the $5.20 per
mcf price realized in the fourth quarter of 2000 for our US production. For the
full year 2000, our average US natural gas price was $3.76 per mcf (1999 - $2.16
per mcf; 1998 - $2.06 per mcf) and our average UK natural gas price was $1.96
per mcf (1999 - $0.96 per mcf; 1998 - $1.40 per mcf).

OIL AND NGLS

Our average oil and ngls price per barrel was $27.72 in 2000 compared to $17.05
in 1999 and $11.74 in 1998. In 1998, the combination of economic problems in
Asia, the mild North American winter and international competition for market
share caused oil prices to fall. Oil prices began to recover when, in the second
quarter of 1999, Organization of Petroleum Exporting Countries' ("OPEC")
production quotas became effective. Starting with the first quarter of 1999, we
experienced seven consecutive quarters of increasing oil and ngls prices before
they leveled out at a price of $30.32 per barrel in the fourth quarter of 2000.


REVENUE

In 2000, an 80% increase in natural gas prices was complemented by a 63%
increase in oil prices. Increased prices more than offset decreased production
with the result that our 2000 production revenue increased 56% from 1999 to
$142.4 million ($117.0 million after royalties). In 1999, growth in our combined
natural gas and oil production volumes was accompanied by a recovery in
commodity prices. As a result, 1999 production revenues increased 22% from 1998
to $91.5 million ($75.4 million after royalties).

<TABLE>
<CAPTION>
NET REVENUE                                2000          1999          1998
-----------------------------------      --------      --------      --------
(in thousands)
<S>                                      <C>           <C>           <C>
Natural gas, after royalties             $ 82,577      $ 50,765      $ 48,501
Oil and ngls, after royalties              34,415        24,601        13,114
                                         --------      --------      --------
Production revenue, after royalties       116,992        75,366        61,615
Interest and other revenue                  2,881         1,081         2,776
                                         --------      --------      --------
Total net revenue                        $119,873      $ 76,447      $ 64,391
                                         ========      ========      ========
</TABLE>


                                       17
<PAGE>   20




<TABLE>
<CAPTION>
                                                        Natural gas
                                              -----------------------------------------         Oil
PRICE/VOLUME VARIANCES, AFTER ROYALTIES          US              UK             Total         and ngls          Total
----------------------------------------      ---------       ---------       ---------       ---------       ---------
(in thousands)
<S>                                           <C>             <C>             <C>             <C>             <C>
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
                                              ---------       ---------       ---------       ---------       ---------
   PRICE VARIANCE                                33,639           1,945          35,584          13,010          48,594
   VOLUME VARIANCE                               (2,197)         (1,575)         (3,772)         (3,196)         (6,968)
                                              ---------       ---------       ---------       ---------       ---------
2000 PRODUCTION REVENUE, AFTER ROYALTIES      $  78,773       $   3,804       $  82,577       $  34,415       $ 116,992
                                              =========       =========       =========       =========       =========
</TABLE>

ROYALTIES

Royalties include payments made to federal and state governments, freehold land
owners and other third parties. Our US Gulf of Mexico properties in US federal
waters generally carry a 16-2/3% royalty rate. Some of these properties carry
overriding royalties ranging from 1.1% to 10%. In 2000, the effective average
overriding royalty rate was 1.9% (1999 - 2.2%; 1998 - 2.7%).

Production from the Aneth and Ratherford Units is subject to production taxes
and 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 26%
royalty.

The UK properties carry no royalty obligations. As the UK 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.

<TABLE>
<CAPTION>
ROYALTIES                           2000         1999         1998
-----------------------------      -------      -------      -------
(in thousands except per unit
amounts and percentages)
<S>                                <C>          <C>          <C>
Natural gas                        $19,006      $11,699      $11,211
Oil and ngls                         6,393        4,442        2,035
                                   -------      -------      -------
Total                              $25,399      $16,141      $13,246
                                   =======      =======      =======
Royalties ($ per mcfe)             $  0.69      $  0.39      $  0.35
Composite royalty rate                17.8%        17.6%        17.7%
</TABLE>

INTEREST AND OTHER REVENUE

Interest and other revenue for 2000 included non-recurring revenue of $1.3
million arising from the Libyan venture which was terminated in the second
quarter of 1999. Under the terms of the concession, the Libyan National Oil
Company ("NOC") reimbursed us and our partners in kind for NOC's share of
production test expenditures. The non-recurring revenue resulted from the
increase in oil prices between the time when production test expenditures were
incurred and the time when reimbursement was effected.

In 1998, interest and other revenue 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.


EXPENSES

PRODUCTION COSTS

Our aggregate production costs in 2000 decreased 2% compared to 1999. However,
because production taxes increased 43% to $2.0 million and production volumes
were lower, our per unit production costs increased. Our production costs in
1999 decreased 12% from 1998, a result of non-recurring items in 1998 and the
termination of the Libyan production test in mid-1999.

Production costs for US Gulf of Mexico region properties were $0.28 per mcfe
($0.35 per mcfe after royalties) in 2000 compared to $0.25 per mcfe ($0.31 per
mcfe after royalties) in 1999 and $0.32 per mcfe ($0.41 per mcfe after
royalties) in 1998. Production costs for the Aneth and Ratherford Units, which
are primarily oil producing properties where secondary and tertiary recovery
methods are being used, were $1.28 per mcfe ($1.47 per mcfe after royalties) in
2000 compared to $1.15 per mcfe ($1.32 per mcfe after royalties) in 1999 and
$0.99 per mcfe ($1.13 per mcfe after royalties) in 1998.


                                       18
<PAGE>   21

<TABLE>
<CAPTION>
PRODUCTION COSTS                              2000         1999         1998
--------------------------------------      -------      -------      -------
(in thousands except per unit amounts)
<S>                                         <C>          <C>          <C>
Lifting costs                               $12,109      $12,929      $14,899
Production taxes                              1,983        1,391        1,456
                                            -------      -------      -------
Production costs                            $14,092      $14,320      $16,355
                                            =======      =======      =======
Production costs ($ per mcfe)
   Before royalty volumes                   $  0.38      $  0.35      $  0.43
   After royalty volumes                    $  0.46      $  0.42      $  0.53
</TABLE>

Production from the Aneth and Ratherford Units and the Northeast Wright and
Chacahoula Fields 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 D. W. Guidry # 1 well in the
Northeast Wright Field, we expect that our production taxes will increase in
2001.

GENERAL AND ADMINISTRATIVE

Our general and administrative costs increased 31% in 2000 compared to 1999 and
decreased 5% in 1999 compared to 1998. Performance-based compensation payments
were higher in 2000 than in 1999 and lower in 1999 than in 1998. Also
contributing to higher costs in 2000 were the hiring of three professional
employees required in support of our larger role as an operator, non-recurring
legal fees and increased office costs.

<TABLE>
<CAPTION>
GENERAL AND ADMINISTRATIVE                     2000           1999           1998
---------------------------------------      --------       --------       --------
(in thousands except per unit
amounts and percentages)
<S>                                          <C>            <C>            <C>
Gross general and administrative             $ 12,040       $  8,527       $  9,108
Capitalized                                    (6,056)        (3,947)        (4,312)
                                             --------       --------       --------
General and administrative expense           $  5,984       $  4,580       $  4,796
                                             ========       ========       ========
General and administrative ($ per mcfe)
   Before royalty volumes                    $   0.16       $   0.11       $   0.13
   After royalty volumes                     $   0.20       $   0.13       $   0.15
Capitalization ratio                               50%            46%            47%
</TABLE>

INTEREST

Interest expense decreased to $1.1 million in 2000 from $2.5 million in 1999 and
$0.4 million in 1998. The fluctuations were largely due to varying credit
facility utilization. Our weighted average debt outstanding during 2000 was
$15.2 million compared to $42.1 million in 1999 and $12.3 million in 1998. The
effective interest rate on our outstanding debt for 2000 was 7.32% compared to
5.93% in 1999 and 6.19% in 1998. The interest rate on our debt at December 31,
2000 was 7.63%.

DEPLETION AND AMORTIZATION

Depletion and amortization expense in 2000 decreased by $7.6 million, compared
to 1999, of which $5.5 million related to the decrease in production and $2.1
million related to the decrease in the average depletion rate to $1.19 per mcfe
($1.44 per mcfe after royalties). Our lower finding and development costs for
proved reserves in 1999, the oil price induced upward revision in our proved
reserves and the ceiling test write-down of UK properties contributed to the
decrease in our depletion rate in 2000.

Comparing 1999 to 1998, depletion and amortization expense increased $9.3
million, of which $4.0 million related to the increase in production and $5.3
million related to the increase in the average depletion rate to $1.25 per mcfe
($1.51 per mcfe after royalties). The downward revision in our proved reserves
at December 31, 1998, the result of low oil prices at that date, contributed to
the increase in our 1999 depletion rate.

We expect that our depletion rate will be approximately $1.35 per mcfe ($1.64
per mcfe after royalties) in the first quarter of 2001. The depletion rate is
reviewed quarterly.

                                       19
<PAGE>   22

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 are not
allowed to exceed the value of estimated future net revenues from those proved
reserves (the "ceiling test"). Full cost accounting rules allow, but do not
require, companies to exclude costs of acquiring and evaluating unproved
properties from their depletion cost centers, 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 centers.

The Canadian full cost accounting guideline was revised during 2000 to require
that a ceiling test must be conducted on a quarterly basis. We will
prospectively apply this policy effective with the first quarter of 2001.

In Libya, we and our partners concluded that the multi-year exploration program,
and the production test which commenced in December 1997, were not commercially
viable 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 was then planned.

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

TAXES

We have available $230.3 million in US tax pools and $29.1 million in Canadian
tax pools to reduce future taxable income. Should natural gas and oil prices
remain at recent levels, we will be required to pay current income taxes in 2001
as follows:

-       US Alternative Minimum Tax ("AMT"), the amounts of which are, for us,
        dependent upon tax loss utilization, and which can be carried forward
        and credited against regular tax in future years; and

-       UK corporate income taxes, the amounts of which will depend primarily on
        UK natural gas prices, and for which we receive limited double-taxation
        relief both in Canada and the US.

During 2000, both the Canadian Federal and Alberta Provincial governments
proposed corporate income tax rate reductions. As our deferred tax asset arises
in Canada, lower corporate income tax rates reduce the future value of the tax
asset. If the proposed rate reductions are all enacted the tax rate for our
Canadian taxable income would fall to 30.12% in 2005, a reduction of about
one-third compared to the 44.62% rate in 2000.

The Canadian Federal rate reductions were substantially enacted in 2000 and we
have recorded the effect, a $1.3 million expense, in 2000. The proposed Alberta
rate reductions did not satisfy the requirements for recognition in 2000. We
expect that the Alberta rate reductions will be substantially enacted in 2001,
at which time we will record their effect, an estimated expense of $1.3 million,
thereby reducing the carrying amount of the deferred tax asset.


NET INCOME (LOSS) APPLICABLE TO COMMON SHARES

In 2000, income before provision for dividends on preferred shares of a
subsidiary increased $39.2 million to $32.3 million compared to 1999. After
provision of $4.9 million for dividends on preferred shares of a subsidiary, net
income applicable to common shares for 2000 was $27.3 million, an improvement of
$39.2 million compared to 1999. The most significant factors responsible for the
improvement were the increased natural gas and oil prices in 2000 and the
non-recurring nature of the 1999 write-off of the Libyan investment.

In 1999, the loss applicable to common shares, after provision of $4.9 million
for dividends on preferred shares of a subsidiary, in 1999 was $11.8 million,
$2.7 million more than in 1998. Improved prices and increased production volumes
realized in 1999 were more than offset by regular and additional depletion
charges.


                                       20
<PAGE>   23

CAPITAL EXPENDITURES

Natural resource capital expenditures were $102.7 million in 2000 compared to
$55.0 million in 1999 and $92.6 million in 1998.

<TABLE>
<CAPTION>
CAPITAL EXPENDITURES SUMMARY                    2000          1999           1998
----------------------------------------      --------      --------       --------
(in thousands)
<S>                                           <C>           <C>            <C>
Property acquisition costs:
   US                                         $  7,789      $  5,352       $  7,903
   UK                                               33            28            115
                                              --------      --------       --------
                                                 7,822         5,380          8,018
                                              --------      --------       --------
Purchase (sale) of producing properties:
   US                                               --          (155)           883
                                              --------      --------       --------
Exploration costs:
   US                                           57,926        28,753         43,317
   UK                                                9             9             72
   Other foreign                                    --         1,531            606
                                              --------      --------       --------
                                                57,935        30,293         43,995
                                              --------      --------       --------
Development costs:
   US                                           36,943        19,542         39,606
   UK                                                1           (39)            71
                                              --------      --------       --------
                                                36,944        19,503         39,677
                                              --------      --------       --------
Total                                         $102,701      $ 55,021       $ 92,573
                                              ========      ========       ========
</TABLE>

LAND AND LEASE HOLDINGS

We acquired leases in two lease sales during 2000. We participated in high bids
for 14 blocks, 5 as operator, covering 72,890 acres (33,684 net acres). Our
share of the bids on the blocks, all of which have been awarded, was $4.3
million. At December 31, 2000, we had an average working interest of 40% in 152
offshore blocks covering 719,798 gross acres compared to an average working
interest of 40% in 139 blocks covering 661,410 gross acres a year earlier.

DRILLING RESULTS

Drilling in all areas, including extensive development drilling in the Utah oil
producing units in 1998, resulted in success rates of 63% in 2000, 70% in 1999
and 84% in 1998. In 2000, our exploratory drilling success rate in the US Gulf
of Mexico region was 59% compared to 73% in 1999 and 43% in 1998. Including
development wells, our success rate in the region was 63% in 2000 compared to
78% in 1999 and 58% in 1998.

<TABLE>
<CAPTION>
                                      2000                  1999                   1998
                                ----------------      ----------------      ----------------
DRILLING RESULTS (wells)        GROSS       NET       Gross       Net       Gross       Net
--------------------------      -----      -----      -----      -----      -----      -----
<S>                             <C>        <C>        <C>        <C>        <C>        <C>
US - Gulf of Mexico region
   Successful                      22       8.38         14       5.37         11       2.79
   Dry                             13       4.80          4       1.70          8       3.45
                                -----      -----      -----      -----      -----      -----
                                   35      13.18         18       7.07         19       6.24
                                -----      -----      -----      -----      -----      -----
US - Other
   Successful                      --         --         --         --         30       6.01
   Dry                             --         --         --         --         --         --
                                -----      -----      -----      -----      -----      -----
                                   --         --         --         --         30       6.01
                                -----      -----      -----      -----      -----      -----
Total US
   Successful                      22       8.38         14       5.37         41       8.80
   Dry                             13       4.80          4       1.70          8       3.45
                                -----      -----      -----      -----      -----      -----
                                   35      13.18         18       7.07         49      12.25
                                -----      -----      -----      -----      -----      -----
Foreign
   Dry                             --         --          2       0.25         --         --
                                -----      -----      -----      -----      -----      -----

Total wells drilled
   Successful                      22       8.38         14       5.37         41       8.80
   Dry                             13       4.80          6       1.95          8       3.45
                                -----      -----      -----      -----      -----      -----

                                   35      13.18         20       7.32         49      12.25
                                =====      =====      =====      =====      =====      =====
</TABLE>

                                       21
<PAGE>   24

In addition to the wells described above, at December 31, 2000 we had an
interest in one (0.67 net) well which was drilling. 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 being drilled or evaluated at December
31, 1998.

Three wells were drilled in 2000 on our leases in the US Gulf of Mexico region
at no cost to us; two are natural gas wells and one was being evaluated at
year-end. In 1999, five wells were drilled on our acreage in the region at no
cost to us; one resulted in a natural gas well and four were unsuccessful. In
1998, one successful natural gas well was drilled on our acreage at no cost to
us.

CAPITAL FIELD DEVELOPMENT ACTIVITY

During 2000, design, construction and/or installation of production facilities
and pipelines, which are the components of our capital field development,
totaled $25.9 million and were principally at Eugene Island 189, High Island
A-510/A-531, High Island A-530, Matagorda Island 704, South Timbalier 196,
Vermilion 267, West Cameron 300 and West Cameron 613/614 where production
facilities and, except at Eugene Island 189 and High Island A-510/A-531,
pipelines, were installed. Onshore, facilities were completed for the Langlinais
#1 well in the Northeast Wright Field and at Chacahoula.


FINDING AND DEVELOPMENT COSTS

COST OF RESERVE ADDITIONS

Three year finding and development costs of proved reserves were $1.17 per mcfe
($1.50 per mcfe after royalties). The upward pressure on exploration service and
supply costs is the primary reason for the increase from the 1999 three year
finding and development cost of $1.15 per mcfe ($1.45 per mcfe after royalties).
The 1998 three year finding and development costs were $1.51 per mcfe ($1.89 per
mcfe after royalties).

In calculating finding costs, a number of anomalies between periods are created
by the timing of expenditures and the phase of the exploration and production
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. Finding costs are calculated by dividing
capital expenditures for a period by proved reserve additions (before
production) for the same period. Both a three-year calculation and one year
components are included in the following table.

<TABLE>
<CAPTION>
                                                                           Cumulative
FINDING COST ANALYSIS                2000          1999          1998      1998 - 2000
-----------------------------      --------      --------      --------    -----------
(in thousands except unit
 and per unit amounts)
<S>                                <C>           <C>           <C>           <C>
Capital expenditures               $102,701      $ 55,021      $ 92,573      $250,295
                                   ========      ========      ========      ========
Proved, before royalties
   Reserve additions (mmcfe)         72,354        80,898        59,999       213,251
   Finding costs ($ per mcfe)      $   1.42      $   0.68      $   1.54      $   1.17
Proved, after royalties
   Reserve additions (mmcfe)         56,164        65,796        45,381       167,341
   Finding costs ($ per mcfe)      $   1.83      $   0.84      $   2.04      $   1.50
</TABLE>

RESERVE REPLACEMENT

For the seventh consecutive year, we added more proved reserves than we produced
with total proved reserves increasing to 326 bcfe (266 bcfe after royalties).
The increase of 72.4 bcfe (56.2 bcfe after royalties), before production,
results in a reserve replacement rate of 197% (185% after royalties).


                                       22
<PAGE>   25
RESERVES

Reports prepared by Netherland, Sewell & Associates, Inc., independent petroleum
engineers, as to our US reserves and internally as to our UK reserves, contain
estimates of our total proved reserves, before and after royalty deductions, as
described below. UK reserves comprise 1.9% (2.3% after royalties) of our total
proved reserves on a bcfe basis.

<TABLE>
<CAPTION>
                                                              Before royalties                            After royalties
                                                  --------------------------------------   ---------------------------------------
                                                  Natural Gas  Oil and ngls   Equivalent   Oil and ngls  Oil and ngls   Equivalent
RESERVE RECONCILIATION                              (mmcf)       (mbbls)       (mmcfe)       (mbbls)       (mbbls)        (mmcfe)
-----------------------------------------------   -----------  ------------   ----------   ------------  ------------   ----------
<S>                                               <C>          <C>            <C>          <C>           <C>            <C>
December 31, 1998                                   159,064        15,227       250,426       129,073        13,134       207,877
                                                   --------      --------      --------      --------      --------      --------
    Purchase of producing properties                     --            --            --            --            --            --
    Revision of previous estimates                   (5,786)        1,607         3,857        (4,858)        1,480         4,022
    Extensions, discoveries and other additions      64,127         2,152        77,041        51,251         1,753        61,774
    Sale of proved properties                            --            --            --            --            --            --
                                                   --------      --------      --------      --------      --------      --------
    Net additions                                    58,341         3,759        80,898        46,393         3,233        65,796
    Production                                      (31,119)       (1,656)      (41,055)      (25,533)       (1,401)      (33,939)
                                                   --------      --------      --------      --------      --------      --------
December 31, 1999                                   186,286        17,330       290,269       149,933        14,966       239,734
                                                   --------      --------      --------      --------      --------      --------
    PURCHASE OF PRODUCING PROPERTIES                  2,741            99         3,335         1,839            66         2,235
    REVISION OF PREVIOUS ESTIMATES                   31,485          (863)       26,307        23,942          (868)       18,734
    EXTENSIONS, DISCOVERIES AND OTHER ADDITIONS      41,280           239        42,712        34,019           196        35,195
    SALE OF PROVED PROPERTIES                            --            --            --            --            --            --
                                                   --------      --------      --------      --------      --------      --------
    NET ADDITIONS                                    75,506          (525)       72,354        59,800          (606)       56,164
    PRODUCTION                                      (27,956)       (1,472)      (36,788)      (22,871)       (1,243)      (30,329)
                                                   --------      --------      --------      --------      --------      --------
DECEMBER 31, 2000                                   233,836        15,333       325,835       186,862        13,117       265,569
                                                   ========      ========      ========      ========      ========      ========
</TABLE>


<TABLE>
<CAPTION>
                                                                      Before royalties                     After royalties
                                                                ------------------------------      ------------------------------
PROVED RESERVE LIFE INDEX (years)                                2000        1999        1998        2000        1999        1998
----------------------------------------------------------      ------      ------      ------      ------      ------      ------
<S>                                                             <C>         <C>         <C>         <C>         <C>         <C>
Natural gas                                                        8.4         6.0         5.3         8.2         5.9         5.3
Oil and ngls                                                      10.4        10.5        13.0        10.6        10.7        13.2
Equivalent                                                         8.9         7.1         6.8         8.8         7.1         6.8
</TABLE>

Reserve life indexes are calculated by dividing year-end reserve volumes by the
year's production volumes



<TABLE>
<CAPTION>
                                                   Before royalties                       After royalties
                                          ---------------------------------      ---------------------------------
RESERVE SUMMARY - NATURAL GAS (mmcf)       2000         1999         1998         2000         1999         1998
------------------------------------      -------      -------      -------      -------      -------      -------
<S>                                       <C>          <C>          <C>          <C>          <C>          <C>
Proved reserves:
    Developed producing - US               98,625       63,822       70,082       77,699       50,531       55,418
                        - UK                5,985        6,376       10,108        5,985        6,376       10,108
    Developed non-producing - US           37,833       58,986       41,974       30,481       46,024       33,906
    Undeveloped - US                       91,393       57,102       36,900       72,697       47,002       29,641
                                          -------      -------      -------      -------      -------      -------
Total proved reserves                     233,836      186,286      159,064      186,862      149,933      129,073
                                          =======      =======      =======      =======      =======      =======
</TABLE>


<TABLE>
<CAPTION>
                                                  Before royalties                     After royalties
                                            ------------------------------      ------------------------------
RESERVE SUMMARY - OIL AND NGLS (mbbls)       2000        1999        1998        2000        1999        1998
--------------------------------------      ------      ------      ------      ------      ------      ------
<S>                                         <C>         <C>         <C>         <C>         <C>         <C>
Proved reserves:
    Developed producing - US                 6,893       7,447       5,430       6,002       6,580       4,739
                        - UK                    19          20          27          19          20          27
    Developed non-producing - US             1,315       1,633       3,329       1,092       1,347       2,768
    Undeveloped - US                         7,106       8,230       6,441       6,004       7,019       5,600
                                            ------      ------      ------      ------      ------      ------
Total proved reserves                       15,333      17,330      15,227      13,117      14,966      13,134
                                            ======      ======      ======      ======      ======      ======
</TABLE>



                                       23
<PAGE>   26

NET FUTURE CAPITAL EXPENDITURES

The reserve reports incorporate estimated future capital expenditures, 89% of
which will be spent over the next five years, that are 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        2000          1999          1998
-------------------------------      --------      --------      --------
(in thousands)
<S>                                  <C>           <C>           <C>
Proved developed                     $ 24,672      $ 28,120      $ 29,131
Proved undeveloped                     97,056        56,753        32,532
                                     --------      --------      --------
Total                                $121,728      $ 84,873      $ 61,663
                                     ========      ========      ========
</TABLE>

RESERVE VALUE RECONCILIATION

As required by the Financial Accounting Standards Board Statement 69, our
reserves were estimated using year-end prices which, at December 31, 2000, were
$24.60 per barrel for oil and $9.68 per mcf for US natural gas. The resulting
estimated present values of proved reserves are not considered to be estimates
of fair market value. WE THEREFORE CAUTION AGAINST SIMPLISTIC USE OF THIS
INFORMATION.

<TABLE>
<CAPTION>
ESTIMATED PRESENT VALUE OF PROVED RESERVES           2000            1999            1998
--------------------------------------------      ----------      ----------      ----------
(in thousands)
<S>                                               <C>             <C>             <C>
Proved developed                                  $  798,646      $  193,935      $  135,867
Proved undeveloped                                   428,313          72,539          16,641
                                                  ----------      ----------      ----------
Total PV-10 value before income taxes             $1,226,959      $  266,474      $  152,508
                                                  ==========      ==========      ==========
Standardized measure of discounted estimated
    future net cash flows after income taxes      $  849,465      $  224,533      $  152,508
                                                  ==========      ==========      ==========
</TABLE>


<TABLE>
<CAPTION>
PRICES USED IN CALCULATING PROVED RESERVES        2000          1999          1998
------------------------------------------      --------      --------      --------
<S>                                             <C>           <C>           <C>
Natural gas (per mcf)
    US                                          $   9.68      $   2.51      $   2.15
    UK                                          $   3.65      $   0.99      $   1.74
Oil and ngls (per barrel)                       $  24.60      $  20.40      $   9.72
</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.

Cash flow from operations, 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, write-down of marketable securities and
deferred income taxes. We generated cash flow from operations of $93.6 million
in 2000 compared to $50.1 million in 1999 and $37.8 million in 1998. The
variances are primarily a function of fluctuating revenues caused by the
volatility of commodity prices.

                                       24
<PAGE>   27

<TABLE>
<CAPTION>
                                                          Before royalties                               After royalties
                                                --------------------------------------       --------------------------------------
CASH FLOW FROM OPERATIONS PER UNIT ANALYSIS       2000           1999           1998           2000           1999           1998
-------------------------------------------     --------       --------       --------       --------       --------       --------
($ per mcfe)
<S>                                             <C>            <C>            <C>            <C>            <C>            <C>
Gross production revenue                        $   3.87       $   2.22       $   1.99
    Royalties                                      (0.69)         (0.39)         (0.35)
                                                --------       --------       --------       --------       --------       --------
Production revenue, after royalties                 3.18           1.83           1.64       $   3.86       $   2.21       $   1.98
    Production costs                               (0.38)         (0.35)         (0.43)         (0.46)         (0.42)         (0.53)
                                                --------       --------       --------       --------       --------       --------
Gross margin                                        2.80           1.48           1.21           3.40           1.79           1.45
    General and administrative expenses            (0.16)         (0.11)         (0.13)         (0.20)         (0.13)         (0.15)
                                                --------       --------       --------       --------       --------       --------
Gross profit                                        2.64           1.37           1.08           3.20           1.66           1.30
    Interest and other                              0.04          (0.03)          0.05           0.05          (0.04)          0.08
    Preferred share dividends                      (0.13)         (0.12)         (0.13)         (0.16)         (0.15)         (0.16)
                                                --------       --------       --------       --------       --------       --------
Cash flow from operations                       $   2.55       $   1.22       $   1.00       $   3.09       $   1.47       $   1.22
                                                ========       ========       ========       ========       ========       ========
Annual production volume (bcfe)                     36.8           41.2           37.7           30.3           34.1           31.1
                                                ========       ========       ========       ========       ========       ========
</TABLE>

In 1997, a third party sold its interests in producing properties that we
currently operate and since that time neither the vendor nor the purchaser has
reimbursed us on a timely basis for expenditures made by us, as operator, for
their account. Accordingly, we commenced an action in the Louisiana courts
against both the vendor and the purchaser to recover the amounts currently owing
to us, approximately $4.6 million, plus interest and costs. Although the
purchaser filed for Chapter 11 bankruptcy in the first half of 2000, we
currently expect to recover all current and future amounts outstanding and have
therefore made no allowance for doubtful collectability.

Our financing activities in 2000 provided $6.7 million of cash, the net result
of:

-       the drawdown of $10 million of our revolving credit facility;

-       the exercise of employee share options for $1.6 million; and

-       the purchase for cancellation of 228,600 common shares for $4.9 million
        under a share repurchase program which expires on August 14, 2001.

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

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

-       the net repayment of $30 million of our revolving credit facility; and

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

Financing activities during 1998 provided $34.5 million of cash, the net result
of:

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

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

-       the purchase for cancellation of 294,700 common shares for $5.9 million
        under a share repurchase program.

Cash used in natural resource investing activities increased to $102.7 million
for 2000 compared to $55.0 million and $92.6 million for 1999 and 1998,
respectively. The components of our natural resource investing activities are as
follows:

<TABLE>
<CAPTION>

NATURAL RESOURCE INVESTING ACTIVITIES           2000          1999           1998
----------------------------------------      --------      --------       --------
(in thousands)
<S>                                           <C>           <C>            <C>
Leasehold and seismic                         $ 11,195      $  7,854       $ 10,757
Purchase (sale) of producing properties             --          (155)           883
Exploratory drilling                            54,562        27,819         41,256
Development drilling                            10,995         9,775         16,517
Capital field development                       25,949         9,728         23,160
                                              --------      --------       --------
Total                                         $102,701      $ 55,021       $ 92,573
                                              ========      ========       ========
</TABLE>



                                       25
<PAGE>   28

Early in the fourth quarter of 2000, we purchased $5 million of marketable
securities. A $1.1 million write-down of the marketable securities, to a
carrying amount approximating their fair value, was recorded at December 31,
2000. Concurrent with the purchase of these shares, we entered into an agreement
giving us an option to acquire Qatari petroleum and natural gas interests. Early
in 2001, the option expired, unexercised.

Our December 31, 2000 cash balance was $8.7 million (1999 - $19.4 million; 1998
- $10.6 million). We had outstanding borrowings of $20 million on our revolving
bank credit facility at December 31, 2000 (1999 - $10 million; 1998 - $40
million). During the third quarter of 2000, our revolving bank credit facility
was reduced to $70 million upon the withdrawal from the syndicate of one lender
for reasons unrelated to us. The original amount of the facility was $100
million. With no immediate need for the $30 million difference, we have decided
to not pursue an immediate replacement for the withdrawn syndicate member. The
weighted average interest rate on our borrowings for 2000 was 7.32% (1999 -
5.93%; 1998 - 6.19%).


RISK ASSESSMENT

There are a number of risks facing the oil and gas industry. Some 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, can result in the injury or death of people, and can
damage property and the environment.

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 US 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 rig supply tightens and drilling
costs rise. Drilling may be unsuccessful for many reasons, including the
inherent imprecision of geological interpretation, 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.

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, particularly in high potential prospects. We
also seek to operate projects in which we participate in order to better control
costs and timing. Additionally, we have increasingly relied on advanced
technologies, including 3D seismic analysis, to define geologic risks, thereby
enhancing the results of our drilling efforts.

ENVIRONMENTAL AND SAFETY RISKS

US 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 affect our business. US offshore oil and gas operations are
subject to regulations of the US 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 UK, deposits of substances or articles at sea from offshore oil and gas
operations are subject to the licensing control of the Ministry of Agriculture,
Fisheries and Food.

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.



                                       26
<PAGE>   29

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 viable. 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 US have been characterized by periods of
unbalanced supply and 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 will 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. The recovery in prices, which started in
1999, continued through 2000, as did price volatility. Natural gas prices affect
us more than oil prices as natural gas was 76% (75% after royalties) of our 2000
and 1999 energy equivalent production and 80% (79% after royalties) of our 1998
energy equivalent production. Primarily because of lower prices, we recorded
ceiling test write-downs of the UK 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 OPEC.

We could be required to write down the carrying value of our natural gas and oil
properties in the future if natural gas and oil 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 affect our cash flow from operating activities. Once incurred,
these write-downs cannot be reversed at a later date.


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 2000, the directors met at
four regularly scheduled meetings. Two additional meeting 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 and the Board is informed of communication activities.
In addition to the Annual Meeting, the Company participates in conferences and
quarterly conference calls. The Company's transfer agent, CIBC Mellon Trust
Company has a toll-free number (1-800-387-0825) to assist shareholders. 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 site at
www.chieftaininternational.com.


                                       27
<PAGE>   30

News releases and other prescribed documents are available on the electronic
databases mandated by the Securities and Exchange Commission known as "EDGAR"
(www.sec.gov/) and by Canadian Securities Authorities known as "SEDAR"
(www.sedar.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.

COMMITTEES OF THE BOARD

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 reviews and recommends to the
Board for its approval the annual financial statements and is also responsible
for reviewing interim unaudited financial statements prior to their release. The
Committee reviews and recommends the annual appointment, terms of engagement and
proposed fees of the independent 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 provides
recommendations to the Board on directors' compensation, appointment and
remuneration of officers and grants of share options. This Committee reviews
compensation and benefits policies, plans and budgets; salaries of certain
non-officer employees; results based compensation; 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 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 and makes recommendations to the Board of
Directors with regard to the Company's retirement plans, related agreements, the
appointment and performance of retirement fund investment managers, and
compliance with the plans' statements of investment policies.

Reserve Committee

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


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:

-       Focus on the US Gulf of Mexico region. We focus our operations on the US
        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.



                                       28
<PAGE>   31

-       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 2001 budget of $105 million for exploration and development
        capital expenditures and we expect to use approximately $65 million of
        this amount for exploration activities. We are currently drilling or
        plan to drill approximately 36 gross exploratory and development wells
        in the US Gulf of Mexico region in 2001. Approximately three-quarters of
        these will be exploratory wells and the remainder are development wells
        to follow up previous discoveries.

-       Manage drilling risks through joint ventures and the use of advanced
        technologies. This element of our strategy is described under
        Operational Risks on page 26.

-       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 interests 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:

-       Financial capability and flexibility. At December 31, 2000, $50 million
        was available under our unsecured revolving credit facility. We seek to
        maintain low levels of debt in order to be able to respond quickly to
        drilling or acquisition opportunities.

-       Substantial inventory of drilling projects in the US Gulf of Mexico
        region. In the US Gulf of Mexico region, we continue to generate, and
        maintain, a two year inventory of 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.

-       Proven exploratory expertise. Our ability to define and participate in
        successful prospects in the US Gulf of Mexico is demonstrated by our
        three year exploratory drilling success rate in the US Gulf of Mexico
        region of 58%.

-       Experienced technical team. Our technical team is comprised of highly
        respected industry professionals with an average of more than 20 years
        of industry experience. Our exploration success is a direct result of
        this team's geologic, geophysical, engineering and technical analysis.

OUR LOOK FORWARD

The fundamentals for US natural gas marketing remain positive. The US Energy
Information Administration ("EIA") reports that US natural gas demand increased
by 3.7% during 2000. For 2001, the EIA forecasts that consumption will be 23.35
trillion cubic feet, an increase of 3% from 2000 levels, even though it expects
wellhead natural gas prices to average $5.22 per mcf. The strong demand for
electricity continues to increase the requirement for natural gas-fired
generation. This, combined with the competing demand for natural gas to refill
storage, should support continued price strength. At year-end 2000, the American
Gas Association reported that storage volumes were 23% lower than the
comparative average for 1996-1998 and 29% lower than at year-end 1999.

On the natural gas supply side, low commodity prices in 1998 and 1999
dramatically reduced drilling. This downturn limited domestic production to 18.6
trillion cubic feet in 2000, an increase of less than 1% from 1999. The EIA is
forecasting that increased drilling activity will support a 5.3% increase in
domestic production in 2001. The active rig count in the US declined by 24% in
1999 to average 625 active rigs compared to 827 in 1998, according to Baker
Hughes. In comparison, the active rig count increased 47% to average 918 in 2000
and had increased to 1,128 by the third week of January 2001. This increased
level of activity reflects the recovery in commodity prices.

The experience of 2000 confirmed the earlier conclusion of many industry
observers that the natural gas supply and demand equation was tightening up in
the US. The balancing of natural gas supply and demand will continue to 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, during periods of
both low and high prices. Our current 2001 exploration and development budget,
which we plan to fund from operating cash flow, is expected to increase 2001
production volumes to 125 mmcfe per day, 24% above 2000 levels. In 2001, we will
benefit from the commencement of production from a number of new offshore
facilities.



                                       29
<PAGE>   32

Our capital expenditures can vary significantly with exploration results,
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 2001 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 2001 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 US Gulf of Mexico region remains optimistic. We
believe that the control on oil prices that can be exerted by OPEC has been
amply demonstrated over the past few years. Should OPEC continue to adhere to
its production quotas, we expect that WTI prices well in excess of $20 per
barrel will continue to prevail.


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

        Management's Report

        Auditors' Report

        Consolidated Balance Sheet as at December 31, 2000 and 1999

        Consolidated Statement of Income (Loss) and Deficit for the years ended
        December 31, 2000, 1999 and 1998

        Consolidated Statement of Cash Flows for the years ended December 31,
        2000, 1999 and 1998

        Notes to Consolidated Financial Statements

        Supplementary Financial Information (Unaudited)

                                       30
<PAGE>   33

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 1, 2001



                                       31
<PAGE>   34

AUDITORS' REPORT


We have audited the consolidated balance sheets of Chieftain International, Inc.
as at December 31, 2000 and 1999 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, 2000. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.

We conducted our audits in accordance with Canadian and United States 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, 2000
and 1999 and the results of its operations and its cash flows for each of the
years in the three-year period ended December 31, 2000 in accordance with
Canadian generally accepted accounting principles.

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



February 1, 2001



                                       32
<PAGE>   35

CONSOLIDATED BALANCE SHEET

Chieftain International, Inc. and Subsidiary Companies

<TABLE>
<CAPTION>
(Full Cost Method of Accounting) as at December 31,               2000            1999
---------------------------------------------------------      ---------       ---------
(US$ in thousands)
<S>                                                            <C>             <C>
ASSETS
Current assets:
    Cash and short-term deposits                               $   8,718       $  19,368
    Accounts receivable                                           32,926          18,855
    Other                                                            754             750
    Marketable securities                                          3,913              --
                                                               ---------       ---------
                                                                  46,311          38,973
                                                               ---------       ---------
Capital assets, at cost:
    Natural resource properties including exploration and
       development thereon (Note 2)                              710,102         607,401
    Other capital assets                                           2,241           2,157
                                                               ---------       ---------
                                                                 712,343         609,558
    Less: Accumulated depletion and amortization                 374,940         332,409
                                                               ---------       ---------
                                                                 337,403         277,149

Deferred income taxes                                             11,746          14,636
                                                               ---------       ---------
                                                               $ 395,460       $ 330,758
                                                               =========       =========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
    Accounts payable and accrued                               $  36,349       $  25,369

Long-term debt (Note 3)                                           20,000          10,000

Abandonment cost accrual                                           9,728           8,595

Deferred income taxes                                             34,237          15,693

Shareholders' equity:
    Preferred shares of a subsidiary (Note 4)                     63,403          63,403
    Share capital (Note 5) --
        Authorized -- an unlimited number of --
            First preferred shares
            Second preferred shares
            Common shares
        Issued --
            16,100,827 common shares (1999 -- 16,224,059)        235,295         237,076
    Contributed surplus                                               --              26
    Deficit                                                       (3,552)        (29,404)
                                                               ---------       ---------
                                                                 295,146         271,101
                                                               ---------       ---------
                                                               $ 395,460       $ 330,758
                                                               =========       =========
</TABLE>

Approved by the Board:



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


                                       33
<PAGE>   36

CONSOLIDATED STATEMENT OF INCOME (LOSS) AND DEFICIT


Chieftain International, Inc. and Subsidiary Companies

<TABLE>
<CAPTION>
Year ended December 31,                                         2000            1999            1998
-----------------------------------------------------        ---------       ---------       ---------
(US$ in thousands except per share amounts)
<S>                                                          <C>             <C>             <C>
Production revenue                                           $ 142,391       $  91,507       $  74,861
    Less: royalties                                             25,399          16,141          13,246
                                                             ---------       ---------       ---------
Production revenue, after royalties                            116,992          75,366          61,615
Interest and other revenue (Note 6)                              2,881           1,081           2,776
                                                             ---------       ---------       ---------
                                                               119,873          76,447          64,391
                                                             ---------       ---------       ---------
Production costs                                                14,092          14,320          16,355
General and administrative expenses                              5,984           4,580           4,796
Interest                                                         1,131           2,496             437
Depletion and amortization                                      43,770          51,385          42,081
Additional depletion                                                --          16,186           6,244
Write-down of marketable securities                              1,079              --              --
                                                             ---------       ---------       ---------
                                                                66,056          88,967          69,913
                                                             ---------       ---------       ---------
Income (loss) before income taxes and
   dividends on preferred shares of a subsidiary                53,817         (12,520)         (5,522)
Income taxes (Note 7):
    Current                                                         93              11              14
    Deferred                                                    21,434          (5,634)         (1,423)
                                                             ---------       ---------       ---------
                                                                21,527          (5,623)         (1,409)
                                                             ---------       ---------       ---------
Income (loss) before dividends on preferred
   shares of a subsidiary                                       32,290          (6,897)         (4,113)
Dividends paid on preferred shares of a subsidiary               4,942           4,942           4,942
                                                             ---------       ---------       ---------
Net income (loss) applicable to common shares                   27,348         (11,839)         (9,055)
Deficit, beginning of year                                     (29,404)        (17,565)         (7,089)
Cost of purchase of common shares in excess
   of stated capital (Note 5)                                   (1,496)             --          (1,421)
                                                             ---------       ---------       ---------

Deficit, end of year                                         $  (3,552)      $ (29,404)      $ (17,565)
                                                             =========       =========       =========

Net income (loss) per common share (Note 8):
    Basic                                                    $    1.69       $   (0.86)      $   (0.67)
                                                             ---------       ---------       ---------
    Diluted (Note 1 (i))                                     $    1.64       $   (0.86)      $   (0.67)
                                                             =========       =========       =========

Weighted average number of common shares outstanding
 (in thousands):
    Basic                                                       16,183          13,701          13,480
                                                             =========       =========       =========
    Diluted                                                     19,745          13,701          13,480
                                                             =========       =========       =========
</TABLE>



                                       34
<PAGE>   37

CONSOLIDATED STATEMENT OF CASH FLOWS


Chieftain International, Inc. and Subsidiary Companies

<TABLE>
<CAPTION>
Year ended December 31,                                          2000            1999            1998
---------------------------------------------------------      ---------       ---------       ---------
(US$ in thousands)
<S>                                                            <C>             <C>             <C>
Operating activities:
    Net income (loss) applicable to common shares              $  27,348       $ (11,839)      $  (9,055)
    Items not requiring a current cash outlay:
        Depletion and amortization                                43,770          67,571          48,325
        Write-down of marketable securities                        1,079              --              --
        Deferred income taxes                                     21,434          (5,634)         (1,423)
                                                               ---------       ---------       ---------
    Cash flow from operations                                     93,631          50,098          37,847
    Change in non-cash operating working capital (Note 9)
        Accounts receivable                                      (14,071)         (4,825)         (3,168)
        Other current assets                                          (4)           (468)            324
        Accounts payable and accrued                               2,897           3,830             164
                                                               ---------       ---------       ---------
                                                                  82,453          48,635          35,167
                                                               ---------       ---------       ---------

Financing activities:
    Issue of common shares                                         1,560          50,321             437
    Purchase of common shares for cancellation                     (4,863)            (80)         (5,902)
    Increase in long-term debt                                    10,000           5,000          40,000
    Decrease in long-term debt                                        --         (35,000)             --
    Financing costs                                                   --          (4,058)             --
                                                               ---------       ---------       ---------
                                                                   6,697          16,183          34,535
                                                               ---------       ---------       ---------

Net cash flows from operating and financing activities            89,150          64,818          69,702
                                                               ---------       ---------       ---------

Investing activities:
    Lease acquisition, exploration and development costs        (102,701)        (55,176)        (91,690)
    Sale of producing properties                                      --             155              --
    Purchase of producing gas and oil properties                      --              --            (883)
                                                               ---------       ---------       ---------
                                                                (102,701)        (55,021)        (92,573)
    Purchase of other capital assets and other                      (182)            (48)            (93)
    Change in investing accounts payable and accrued               8,083            (994)          6,652
    Investment in marketable securities                           (5,000)             --              --
                                                               ---------       ---------       ---------
                                                                 (99,800)        (56,063)        (86,014)
                                                               ---------       ---------       ---------

Change in cash and short-term deposits                           (10,650)          8,755         (16,312)
Cash and short-term deposits, beginning of year                   19,368          10,613          26,925
                                                               ---------       ---------       ---------

Cash and short-term deposits, end of year                      $   8,718       $  19,368       $  10,613
                                                               =========       =========       =========
</TABLE>



                                       35
<PAGE>   38

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(DECEMBER 31, 2000, 1999 AND 1998)

CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES *

We are engaged in natural gas and oil exploration, development and production
primarily in the United States ("US") and also in the United Kingdom ("UK")
sector of the North Sea. The Consolidated Financial Statements are expressed in
US currency as most of our assets and operations are denominated in US dollars.

        1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

                (a)     ACCOUNTING PRINCIPLES

                        Our financial statements are prepared in conformity with
                        Canadian generally accepted accounting principles. The
                        preparation of financial statements in conformity with
                        generally accepted accounting principles requires
                        management to make informed judgements and estimates.
                        Actual results may differ from those estimates. Material
                        differences between Canadian and US accounting
                        principles that affect us 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 our
                        accounts and the accounts of our subsidiary companies,
                        all of which are wholly-owned except for Chieftain
                        International Funding Corp., a US subsidiary which in
                        1992 issued 2,726,700 preferred shares to the public.
                        These preferred shares are convertible into common
                        shares of Chieftain International, Inc. See Note 4.

                        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)     MARKETABLE SECURITIES

                        Our interest in marketable securities is accounted for
                        by the cost method. Application of the cost method
                        results in the investment initially being recorded at
                        cost and earnings therefrom are recognized only to the
                        extent that dividends are received or are receivable.
                        The amount of the investment is reduced by any dividends
                        received in excess of our pro rata share of
                        post-acquisition income.

                (d)     FOREIGN CURRENCY TRANSLATION

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

                (e)     FINANCIAL ASSETS AND LIABILITIES

                        Our financial instruments that are included in the
                        Consolidated Balance Sheet are comprised of cash and
                        short-term deposits, accounts receivable, marketable
                        securities, all current liabilities and long-term debt.
                        In each case, their fair value approximates the carrying
                        amount reflecting 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. Marketable securities
                        are subject to currency, market and liquidity risks: the
                        shares trade in Canadian currency, share prices are
                        volatile and timely divestiture may not be possible at
                        share prices approximating fair value. Long-term debt is
                        subject to normal floating interest rate risk.

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



                                       36
<PAGE>   39

                (f)     NATURAL RESOURCE PROPERTIES

                        We account for natural gas and oil properties in
                        accordance with the Canadian guideline 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, using the
                        ratio of 1 barrel of oil = 6,000 cubic feet of natural
                        gas. 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. See Note 2.

                (g)     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.

                (h)     INCOME TAXES

                        Income taxes are recorded using the liability method of
                        accounting. Applying this method, deferred income taxes
                        are recognized, using applicable, enacted, or
                        substantively enacted, income tax rates, for future
                        income tax consequences attributable to differences
                        between the financial statement carrying values and
                        their respective income tax bases. The effect of a
                        change in tax rates on deferred income tax assets and
                        liabilities 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.

                (i)     PER SHARE AMOUNTS

                        Effective with the fourth quarter of 2000, we
                        retroactively adopted revised per share calculation
                        methods which are required to be adopted no later than
                        2001 under Canadian generally accepted accounting
                        principles. Consistent with the revision, we now include
                        share options in diluted per share amounts, where
                        dilutive, assuming that the share options are exercised
                        using the treasury stock method.

                        The retroactive application of this policy had the
                        effects of increasing our diluted income per common
                        share by $0.05 in 2000. All relevant amounts for prior
                        periods have been restated for consistency and
                        comparability.

        2. NATURAL RESOURCE PROPERTIES

        The following weighted average December 31 field prices were used in the
        determination of our US future net revenues for purposes of the ceiling
        test:

<TABLE>
<CAPTION>
As at December 31,                                   2000          1999          1998
---------------------------------------------      --------      --------      --------
<S>                                                <C>           <C>           <C>
Oil and ngls (per barrel)                          $  24.60      $  20.40      $  12.27
Natural gas (per thousand cubic feet ("mcf"))      $   9.68      $   2.51      $   2.15
</TABLE>

        A field price of $3.65 (1999 - $0.99; 1998 - $1.74) per mcf was used in
        the determination of our UK future net revenues for purposes of the
        ceiling test.

        There is uncertainty as to the prices at which natural gas and oil
        produced by us may be sold in the future.



                                       37
<PAGE>   40

        The application of the ceiling test to US property carrying costs at
        December 31, 1998, using the $12.27 per barrel average oil and natural
        gas liquids ("ngls") price received by us during the year and the $2.15
        per mcf December 31, 1998 natural gas price, required no write-down. At
        December 31, 1998, a write-down of $10,614,000, after providing for tax
        recoveries of $5,842,000, would have been required had prices as of that
        date, $2.15 per mcf for natural gas and $9.72 per barrel for oil and
        ngls, been used. At December 31, 1999 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 of
        that date. 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 UK properties.

        Depletion rates per physical unit of US production are as follows:

<TABLE>
<CAPTION>
                               Natural Gas      Oil and ngls
                                (per mcf)       (per barrel)
                               -----------      ------------
<S>                            <C>              <C>
Year ended December 31, 1998      $1.16            $6.97
Year ended December 31, 1999      $1.25            $7.50
YEAR ENDED DECEMBER 31, 2000      $1.23            $7.36
</TABLE>

        The depletion rate per physical unit of UK natural gas production was
        $0.51 per mcf for the year ended December 31, 2000 (1999 - $1.24; 1998 -
        $0.81).

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

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

<TABLE>
<CAPTION>
Year ended December 31,       2000        1999        1998
-----------------------      ------      ------      ------
(in thousands)
<S>                          <C>         <C>         <C>
Lease acquisition            $1,849      $  765      $  857
Exploration                   2,660       1,581       1,740
Development                   1,547       1,601       1,715
                             ------      ------      ------
                             $6,056      $3,947      $4,312
                             ======      ======      ======
</TABLE>

        3. REVOLVING CREDIT AND LONG-TERM DEBT

           In 1997 we arranged an unsecured revolving credit facility with a
           syndicate of banks. The facility, in the amount of $70 million (1999
           - $100 million)or the Canadian dollar equivalent, is fully revolving
           for 364 day periods with extensions at the option of the lenders upon
           our request. 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 rate, US base rate, Bankers'
           Acceptance rate or LIBOR plus applicable margins. Certain financial
           tests are required to be met quarterly. Under this facility, $20
           million was utilized at December 31, 2000 (1999 - $10 million),
           carrying a weighted average interest rate of 7.63% (1999 - 7.00%).

        4. 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 US. The preferred shares are
           redeemable, at the option of Funding, at $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

        5. SHARE CAPITAL

                (a) COMMON SHARES

<TABLE>
<CAPTION>
Year ended December 31,                                2000                              1999                       1998
-----------------------                     --------------------------        -------------------------    -----------------------
                                              NUMBER           SHARE            NUMBER          SHARE        NUMBER        SHARE
                                                OF            CAPITAL             OF           CAPITAL         OF         CAPITAL
                                              SHARES          ACCOUNT           SHARES         ACCOUNT       SHARES       ACCOUNT
                                            -----------       --------        ----------       --------    ----------     --------
(in thousands except number of shares)
<S>                                         <C>               <C>             <C>              <C>         <C>            <C>
Balance, beginning of year                   16,224,059       $237,076        13,355,891       $189,108    13,622,375     $192,845
    Share options exercised                     105,368          1,560               668              9        28,216          437
    Shares purchased and cancelled*            (228,600)        (3,341)           (7,500)          (106)     (294,700)      (4,174)
    Shares issued for cash**                         --             --         2,875,000         48,065            --           --
                                            -----------       --------        ----------       --------    ----------     --------
Balance, end of year                         16,100,827       $235,295        16,224,059       $237,076    13,355,891     $189,108
                                            ===========       ========        ==========       ========    ==========     ========
</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, we sold 2,875,000 common shares by way of
        a public offering in the US at $17.50 per share.

                (b)     COMMON SHARES RESERVED

                        At December 31, 2000, 1,394,632 (1999 - 1,130,207; 1998
                        - 1,130,875) of our authorized but unissued common
                        shares were reserved for issuance under the Share Option
                        Plan. See Note 5(d).

                        We have reserved 3,408,375 common shares for issuance
                        pursuant to the conversion provisions of the preferred
                        shares of a subsidiary. See Note 4.

                (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.

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

                        The Plan provides for the granting of options to
                        employees, directors and consultants to purchase our
                        common shares. 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, 2000 options
                        were outstanding to 60 participants in the Plan.

                        The following is a summary of activity related to the
                        Plan for the years ended December 31, 2000, 1999 and
                        1998.

<TABLE>
<CAPTION>
Year ended December 31,                          2000                         1999                           1998
-----------------------               --------------------------    --------------------------    --------------------------
                                                        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        1,119,189       $16.58        1,083,857       $16.74        1,057,673       $  16.47
    Granted                               233,000        20.26          180,000        13.44           65,000          21.08
    Exercised                            (105,368)       14.81             (668)       13.63          (28,216)         15.49
    Forfeited                              (2,000)       21.32           (4,000)       22.54          (10,600)         20.07
    Expired                                    --           --         (140,000)       13.61               --             --
                                      -----------       --------    -----------       --------    -----------       --------
Outstanding at end of year              1,244,821        17.41        1,119,189        16.58        1,083,857          16.74
                                      ===========       ========    ===========       ========    ===========       ========
Options exercisable at year=end           870,155                       824,521                       869,858
                                      ===========                   ===========                   ===========
</TABLE>



                                       39
<PAGE>   42

           The following table summarizes information about options outstanding
           at December 31, 2000.

<TABLE>
<CAPTION>
                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 -- 15.38            620,287          5.1 years          $14.18            510,287           $  14.43
  18.00 -- 20.88            361,334          7.2 years           19.81            115,001              19.21
  20.94 -- 23.75            263,200          6.6 years           21.74            244,867              21.69
                          ---------                                              --------
                          1,244,821                                               870,155
                          =========                                              ========
</TABLE>

        6. INTEREST AND OTHER REVENUE

           Interest and other revenue for 2000 included non-recurring revenue of
           $1.3 million arising from the Libyan venture which was terminated in
           the second quarter of 1999. Under the terms of the concession, the
           Libyan National Oil Company ("NOC") reimbursed us and our partners in
           kind for NOC's share of production test expenditures. The
           non-recurring revenue resulted from the increase in oil prices
           between the time when production test expenditures were incurred and
           the time when reimbursement was effected.

           In 1998, interest and other revenue 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
           of $1,129,000, $282,000 and $189,000, respectively.

        7. INCOME TAXES

           Income tax expense is made up of the following components:

<TABLE>
<CAPTION>
Year ended December 31,                                     2000                        1999                       1998
-----------------------                             ----------------------    -----------------------     -----------------------
                                                    CANADA           US        Canada          US          Canada           US
                                                    --------      --------    --------       --------     --------       --------
(in thousands)
<S>                                                 <C>           <C>         <C>            <C>          <C>            <C>
Income (loss) before income taxes and
   dividends on preferred shares of a subsidiary    $  1,043      $ 52,774    $(18,254)      $  5,734     $ (6,829)      $  1,307
                                                    ========      ========    ========       ========     ========       ========
Income taxes (recovery)
    Current                                         $     --      $     93    $     11       $     --     $     14       $     --
    Deferred                                           2,890        18,544      (7,643)         2,009       (1,740)           317
                                                    --------      --------    --------       --------     --------       --------
                                                    $  2,890      $ 18,637    $ (7,632)      $  2,009     $ (1,726)      $    317
                                                    ========      ========    ========       ========     ========       ========
</TABLE>

                                       40
<PAGE>   43

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

<TABLE>
<CAPTION>
Year ended December 31,                                             2000           1999           1998
------------------------------------------------------------      --------       --------       --------
(in thousands)
<S>                                                               <C>            <C>            <C>
Tax at statutory rate of 44.62%
   (Combined Canadian Federal and provincial rate)                $ 24,013       $ (5,587)      $ (2,465)
Add (deduct) the effect of:
    Lower income tax rate on earnings of US subsidiaries            (4,766)          (496)           (81)
    Canadian income tax on exchange loss
       which is eliminated upon consolidation                          426            909            631
    Reduction in value of deferred tax assets resulting from
       reduction in future Canadian rate                             1,318             --             --
    Other                                                              536           (449)           506
                                                                  --------       --------       --------
Tax at effective rate                                             $ 21,527       $ (5,623)      $ (1,409)
                                                                  ========       ========       ========
Effective tax rate                                                  40.0 %         44.9 %         25.5 %
                                                                  ========       ========       ========
</TABLE>

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

<TABLE>
<CAPTION>
                                                           2000                                         1999
                                           -------------------------------------       -------------------------------------
As at December 31,                          CANADA          US           TOTAL          Canada          US            Total
-------------------------------------      --------      --------       --------       --------      --------       --------
(in thousands)
<S>                                        <C>           <C>            <C>            <C>           <C>            <C>
Deferred tax assets
    Depletion and amortization             $  8,588      $     --       $  8,588       $ 10,679      $     --       $ 10,679
    Financing costs                           1,254            --          1,254          2,005            --          2,005
    Loss carryforwards                          681        26,656         27,337          1,461        26,645         28,106
    Other                                     1,223            14          1,237            491             4            495
                                           --------      --------       --------       --------      --------       --------
                                             11,746        26,670         38,416         14,636        26,649         41,285
                                           --------      --------       --------       --------      --------       --------
Deferred tax liabilities
    Depletion and amortization                   --       (60,907)       (60,907)            --       (42,342)       (42,342)
                                           --------      --------       --------       --------      --------       --------
Net deferred tax assets (liabilities)      $ 11,746      $(34,237)      $(22,491)      $ 14,636      $(15,693)      $ (1,057)
                                           ========      ========       ========       ========      ========       ========
</TABLE>

           At December 31, 2000 our net operating tax losses carried forward are
           summarized in the following table. We are of the opinion that the tax
           benefit of these tax losses will be realized.

<TABLE>
<CAPTION>
Year of expiry       Canada           US
--------------      -------      -------
(in thousands)
<S>                 <C>          <C>
2003                $ 1,492      $    --
2005                    239        6,119
2007                     --        2,835
2009                     --        6,139
2010                     --       18,007
2011                     --        3,773
2012                     --        2,090
2018                     --       16,088
2019                     --       19,221
2020                     --          814
                    -------      -------
Total               $ 1,731      $75,086
                    =======      =======
</TABLE>



                                       41
<PAGE>   44

        8. PER SHARE AMOUNTS

           Basic net income (loss) per common share is calculated by dividing
           net income (loss) applicable to common shares by the weighted average
           number of common shares outstanding during the year. Diluted income
           (loss) per common share is calculated to give effect to share options
           and shares issuable on conversion of preferred shares.

<TABLE>
<CAPTION>
Year ended December 31,                                             2000          1999           1998
------------------------------------------------------------      --------      --------       --------
(in thousands)
<S>                                                               <C>           <C>            <C>
Net income (loss) applicable to common shares                     $ 27,348      $(11,839)      $ (9,055)
Dividends paid on preferred shares of a subsidiary                   4,942            --             --
                                                                  --------      --------       --------
Diluted net income (loss)                                         $ 32,290      $(11,839)      $ (9,055)
                                                                  ========      ========       ========
</TABLE>


<TABLE>
<CAPTION>
Year ended December 31,                                             2000          1999           1998
                                                                  --------      --------       --------
(shares in thousands)
<S>                                                               <C>           <C>            <C>
Basic weighted average number of common shares outstanding          16,183        13,701         13,480
Effect of dilutive securities
    Exercise of share options                                          154            --             --
    Conversion of preferred shares                                   3,408            --             --
                                                                  --------      --------       --------
Diluted weighted average number of common shares outstanding        19,745        13,701         13,480
                                                                  ========      ========       ========
</TABLE>

        9. SUPPLEMENTAL CASH FLOW INFORMATION

           Net cash outflows for (inflows from) income taxes were $211,000,
           $(12,000) and $14,000 for the years 2000, 1999 and 1998,
           respectively. Cash outflows for long-term debt interest were
           $1,032,000, $2,601,000 and $628,000 in 2000, 1999 and 1998,
           respectively.

        10. PENSION COSTS AND OBLIGATIONS

           We contributed $178,416, $145,418 and $145,300 for 2000, 1999 and
           1998, respectively, to defined contribution pension plans. Under a
           supplementary defined contribution pension plan established in 1991,
           costs of $209,484, $216,401 and $198,294 for 2000, 1999 and 1998,
           respectively, and the related liability are recorded in the accounts.
           We have established no other post-employment benefit plans.

        11. SEGMENTED INFORMATION

           We have a single reportable segment with activities as explained in
           the preamble to the Notes. Production revenue, after royalties, all
           of which arises from external customers, is attributed to the country
           in which the underlying production occurred. Most of the US natural
           gas, oil and ngls we produce are marketed by a single aggregator.
           Production revenues, after royalties, associated with the aggregator
           were $90,842,000 (1999 - $59,665,000; 1998 - $46,340,000). As at
           December 31, 2000, we had entered into natural gas forward contracts
           with the aggregator. The forward contracts are for the physical
           delivery of, during the first nine months of the following year,
           natural gas volumes totalling 7.1 billion cubic feet ("bcf") (1999 -
           6.1 bcf), at an average price of $4.86 per mcf (1999 - $2.49 per
           mcf). Our 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, after royalties, associated
           with sales to the regional refiner were $14,188,000 (1999 -
           $9,710,000; 1998 - $8,207,000). At December 31, 1999, we had entered
           into an oil forward contract with the regional refiner for the
           physical delivery, in 2000, of oil volumes of 90,000 barrels at an
           average price of $19.00 per barrel. We believe that alternative
           marketing arrangements would be readily available for our natural
           gas, oil and ngls.

                                       42
<PAGE>   45

<TABLE>
<CAPTION>
                                                 2000          1999          1998
                                               --------      --------      --------
(in thousands)
<S>                                            <C>           <C>           <C>
Production revenue, after royalties
    US                                         $113,005      $ 71,487      $ 56,199
    UK                                            3,987         3,582         4,411
    Libya                                            --           297         1,005
                                               --------      --------      --------
Total production revenue, after royalties       116,992        75,366        61,615
Interest and other revenue                        2,881         1,081         2,776
                                               --------      --------      --------

Total revenue                                  $119,873      $ 76,447      $ 64,391
                                               ========      ========      ========

Net capital assets
    US                                         $336,114      $274,904      $267,020
    UK                                            1,013         1,994        11,337
    Canada and other                                276           251           285
    Libya                                            --            --         9,835
                                               --------      --------      --------

                                               $337,403      $277,149      $288,477
                                               ========      ========      ========
</TABLE>

        12. US ACCOUNTING PRINCIPLES

                (a)     FULL COST ACCOUNTING

                        US full cost accounting rules differ materially from the
                        Canadian full cost accounting guidelines we follow. In
                        determining the limitation on carrying values, US rules
                        require the discounting of future net revenues at 10%,
                        and Canadian guidelines require the use of undiscounted
                        future net revenues and the deduction of estimated
                        future administrative and financing costs. During 1999
                        and 1998, impairment adjustments would have been
                        required under US accounting rules. The quarterly test
                        required by US accounting rules, using a March 31, 1999
                        UK natural gas price of $0.84 per mcf to determine
                        future net revenues, would have resulted in a write-down
                        of UK 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 US natural gas and oil prices of
                        $2.15 per mcf and $9.72 per barrel to determine future
                        net revenues would have resulted in a write-down of US
                        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. Using June 30, 1998 US prices of $2.09 per mcf and
                        $12.40 per barrel to determine future net revenues would
                        have resulted in a write-down of US property carrying
                        costs of $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
                        would result in reduced depletion expense, under US
                        rules, for subsequent periods. In 1999, under Canadian
                        guidelines the test resulted in a write-down of UK
                        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 US accounting rules.



                                       43
<PAGE>   46

                (b)     EFFECT ON EARNINGS

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

<TABLE>
<CAPTION>

Year ended December 31,                                                   2000           1999           1998
------------------------------------------------------------------      --------       --------       --------
(in thousands except per share amounts)
<S>                                                                     <C>            <C>            <C>
Net income (loss) applicable to
   common shares, as reported                                           $ 27,348       $(11,839)      $ (9,055)
Additional depletion difference                                               --         (2,311)       (89,153)
                                                                        --------       --------       --------
                                                                          27,348        (14,150)       (98,208)
                                                                        --------       --------       --------
Reduction in depletion expense                                            11,042         17,623          4,235
Reduction (increase) in deferred tax provision                            (2,657)        (5,440)        30,010
                                                                        --------       --------       --------

Net income (loss) applicable to common
   shares under US accounting principles                                $ 35,733       $ (1,967)      $(63,963)
                                                                        ========       ========       ========

Net income (loss) per common share under US accounting principles:
    Basic                                                               $   2.21       $  (0.14)      $  (4.75)
                                                                        ========       ========       ========
    Diluted                                                             $   2.06       $  (0.14)      $  (4.75)
                                                                        ========       ========       ========

Diluted common shares outstanding                                         19,745         13,701         13,480
                                                                        ========       ========       ========
</TABLE>

                (c)     EFFECT ON BALANCE SHEET

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

<TABLE>
<CAPTION>
As at December 31,                       2000                            1999
------------------             --------------------------      --------------------------
                                                UNDER US                        Under US
                                  AS           ACCOUNTING         As           Accounting
                                REPORTED       PRINCIPLES      Reported        Principles
                               ---------       ----------      ---------       ----------
(in thousands)
<S>                            <C>             <C>             <C>             <C>
Net capital assets             $ 337,403       $ 260,797       $ 277,149       $ 189,501
Deferred tax -- asset             11,746          13,675          14,636          30,238
Deferred tax -- liability         34,237           7,528          15,693              --
Deficit                           (3,552)        (51,520)        (29,404)        (85,757)
</TABLE>

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

                (d)     INCOME TAX DISCLOSURES

                        Provisions for deferred income taxes are as follows:

<TABLE>
<CAPTION>
Year ended December 31,                                         2000                      1999                       1998
-----------------------                                ----------------------    -----------------------   -----------------------
                                                        CANADA          US        Canada          US        Canada           US
                                                       --------      --------    --------       --------   --------       --------
(in thousands)
<S>                                                    <C>           <C>         <C>            <C>        <C>            <C>
Income (loss) before income taxes and
   dividends on preferred shares of a subsidiary       $  1,648      $ 63,211    $(17,492)      $ 20,284   $ (5,002)      $(85,440)
                                                       ========      ========    ========       ========   ========       ========
Provision for deferred income taxes                    $  1,842      $ 22,249    $ (7,248)      $  7,054   $   (921)      $(30,512)
                                                       ========      ========    ========       ========   ========       ========
</TABLE>



                                       44
<PAGE>   47

                        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,                                     2000           1999            1998
--------------------------------------------------      --------       --------        --------
(in thousands)
<S>                                                     <C>            <C>             <C>
Tax at statutory Canadian rate of 44.62%                $ 28,940       $  1,247        $(40,355)
    Lower income tax rate on earnings of
       US subsidiaries                                    (5,717)        (1,823)          7,830
    Canadian income tax on exchange
       loss which is eliminated upon consolidation           426            909             631
    Exchange revaluation of Canadian
       deferred tax assets                                   515           (553)            280
    Other                                                     20             37             195
                                                        --------       --------        --------
Tax at effective rate                                   $ 24,184       $   (183)       $(31,419)
                                                        ========       ========        ========
Effective tax rate                                        37.3 %           (6.6)%        34.7 %
                                                        ========       ========        ========
</TABLE>

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

<TABLE>
<CAPTION>
                                                          2000                                          1999
                                           -------------------------------------       -------------------------------------
As at December 31,                          CANADA          US            TOTAL         Canada          US            Total
-------------------------------------      --------      --------       --------       --------      --------       --------
(in thousands)
<S>                                        <C>           <C>            <C>            <C>           <C>            <C>
Deferred tax assets
    Depletion and amortization             $ 10,155      $     --       $ 10,155       $ 11,561      $     --       $ 11,561
    Financing costs                           1,374            --          1,374          2,005            --          2,005
    Loss carryforwards                          772        26,656         27,428          1,461        26,645         28,106
    Other                                     1,374            15          1,389            490             5            495
                                           --------      --------       --------       --------      --------       --------
                                             13,675        26,671         40,346         15,517        26,650         42,167
                                           --------      --------       --------       --------      --------       --------
Deferred tax liabilities
    Depletion and amortization                   --       (34,199)       (34,199)            --       (11,929)       (11,929)
                                           --------      --------       --------       --------      --------       --------
Net deferred tax assets (liabilities)      $ 13,675      $ (7,528)      $  6,147       $ 15,517      $ 14,721       $ 30,238
                                           ========      ========       ========       ========      ========       ========
</TABLE>

                (e)     STOCK-BASED COMPENSATION

                        We apply the intrinsic value method prescribed by APB
                        Opinion 25 and related interpretations in accounting for
                        share option transactions. Accordingly, no compensation
                        cost is recognized in the accounts. US accounting
                        principles require disclosure of the impact on earnings
                        and earnings per share of the value of options granted
                        after 1994, calculated in accordance with FAS 123.



                                       45
<PAGE>   48

                        Such impact, using fair values of $11.38, $7.75 and
                        $10.61 for options granted in 2000, 1999 and 1998,
                        respectively, would approximate the following pro forma
                        amounts.

<TABLE>
<CAPTION>
Year ended December 31,                               2000            1999             1998
---------------------------------------------      ----------      ----------       ----------
(in thousands except per share amounts)
<S>                                                <C>             <C>              <C>
Compensation costs, net of tax                     $    1,361      $    1,255       $    1,502
Net income (loss) applicable to common shares
    As reported                                    $   35,733      $   (1,967)      $  (63,963)
    Pro forma                                      $   34,372      $   (3,222)      $  (65,465)
Net income (loss) per common share
    Basic
        As reported                                $     2.21      $    (0.14)      $    (4.75)
        Pro forma                                  $     2.12      $    (0.24)      $    (4.86)
    Diluted
        As reported                                $     2.06      $    (0.14)      $    (4.75)
        Pro forma                                  $     2.01      $    (0.24)      $    (4.86)
</TABLE>

                        The fair value of each option granted is estimated on
                        the date of grant using the Black-Scholes option pricing
                        model with weighted average assumptions for grants as
                        follows:

<TABLE>
<CAPTION>
Year ended December 31,       2000         1999        1998
-----------------------      ------       ------      ------
<S>                          <C>          <C>         <C>
Risk free interest rate      6.48 %       5.68 %      5.64 %
Expected lives (years)           10           10          10
Expected volatility              29%        28 %        25 %
Dividends                      NONE         None        None
</TABLE>

                (f)     RECENT ACCOUNTING PRONOUNCEMENTS

                        FAS 133, Accounting for Derivative Instruments and
                        Hedging Activities, as amended by FAS 138, is first
                        effective for our 2001 fiscal year. FAS 133 currently
                        has no affect on us as our derivative instruments
                        qualify for the normal purchases and normal sales
                        exception.



                                       46
<PAGE>   49

SUPPLEMENTARY FINANCIAL INFORMATION


CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
DECEMBER 31, 2000

(Unaudited)

RESERVE INFORMATION

Reports prepared by Netherland, Sewell & Associates, Inc. as to our US reserves
and by ourselves as to the UK reserves, estimate the total proved reserves owned
by us, before and after royalty deductions, as follows:

<TABLE>
<CAPTION>
                                                                   Natural Gas -- mmcf           Oil and ngls -- mbbls*
                                                       --------------------------------------    ----------------------
TOTAL PROVED RESERVES -- BEFORE ROYALTY DEDUCTIONS        US             UK           Total                 US
-------------------------------------------------      --------       --------       --------           --------
<S>                                                    <C>            <C>            <C>                <C>
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
    PURCHASE OF PRODUCING PROPERTIES                      2,741             --          2,741                 99
    REVISION OF PREVIOUS ESTIMATES                       29,936          1,549         31,485               (870)
    EXTENSIONS, DISCOVERIES AND OTHER ADDITIONS          41,280             --         41,280                239
    SALE OF PROVED PROPERTIES                                --             --             --                 --
    PRODUCTION                                          (26,016)        (1,940)       (27,956)            (1,464)
                                                       --------       --------       --------           --------

DECEMBER 31, 2000                                       227,851          5,985        233,836             15,314
                                                       ========       ========       ========           ========
</TABLE>


<TABLE>
<CAPTION>
                                                                   Natural Gas -- mmcf           Oil and ngls -- mbbls*
                                                       --------------------------------------    ----------------------
Total Proved Reserves -- After Royalty Deductions         US             UK            Total                US
-------------------------------------------------      --------       --------        -------           --------
<S>                                                    <C>            <C>             <C>               <C>
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
    PURCHASE OF PRODUCING PROPERTIES                     1,839             --           1,839                 66
    REVISION OF PREVIOUS ESTIMATES                      22,393          1,549          23,942               (875)
    EXTENSIONS, DISCOVERIES AND OTHER ADDITIONS         34,019             --          34,019                196
    SALE OF PROVED PROPERTIES                               --             --              --                 --
    PRODUCTION                                         (20,931)        (1,940)        (22,871)            (1,235)
                                                       -------        -------        --------           --------

DECEMBER 31, 2000                                      180,877          5,985         186,862             13,098
                                                       =======        =======        ========           ========
</TABLE>

* 19,100 (1999 - 20,100) barrels of natural gas liquids, before and after
  royalty deductions, associated with the UK gas reserves are not included in
  this table.



                                       47
<PAGE>   50

(Unaudited)
<TABLE>
<CAPTION>
                                                                            Natural Gas -- mmcf         Oil and ngls -- mbbls
                                                                     ---------------------------------  ---------------------
PROVED DEVELOPED PRODUCING RESERVES - BEFORE ROYALTY DEDUCTIONS        US           UK          Total            US
---------------------------------------------------------------      -------      -------      -------        -------
<S>                                                                  <C>          <C>          <C>            <C>
December 31, 1998                                                     70,082       10,108       80,190          5,430
December 31, 1999                                                     63,822        6,376       70,198          7,447
DECEMBER 31, 2000                                                     98,625        5,985      104,610          6,893
</TABLE>

<TABLE>
<CAPTION>
                                                                         Natural Gas -- mmcf        Oil and ngls -- mbbls
                                                                    ------------------------------  ---------------------
PROVED DEVELOPED PRODUCING RESERVES - AFTER ROYALTY DEDUCTIONS        US          UK        Total             US
--------------------------------------------------------------      ------      ------      ------          ------
<S>                                                                 <C>         <C>        <C>              <C>
December 31, 1998                                                   55,418      10,108      65,526           4,739
December 31, 1999                                                   50,531       6,376      56,907           6,580
DECEMBER 31, 2000                                                   77,699       5,985      83,684           6,002
</TABLE>

RESULTS OF OPERATIONS FOR GAS AND OIL PRODUCING ACTIVITIES

<TABLE>
<CAPTION>
Year ended December 31,                               2000            1999            1998
---------------------------------------------      ---------       ---------       ---------
(in thousands)
<S>                                                <C>             <C>             <C>
US
    Revenue -- net of royalties                    $ 113,005       $  71,487       $  56,199
    Production costs                                 (16,861)        (18,128)        (15,675)
    Depletion and amortization                       (42,680)        (46,796)        (39,460)
                                                   ---------       ---------       ---------
    Results of operations before income taxes         53,464           6,563           1,064
    Income tax (expense) recovery                    (18,966)         (2,300)           (333)
                                                   ---------       ---------       ---------
    Results of operations after income taxes          34,498           4,263             731
                                                   ---------       ---------       ---------
UK
    Revenue -- net of royalties                        3,987           3,582           4,411
    Production costs                                    (256)           (338)           (964)
    Depletion and amortization                        (1,016)         (9,304)         (3,646)
                                                   ---------       ---------       ---------
    Results of operations before income taxes          2,715          (6,060)           (199)
    Income tax (expense) recovery                     (1,088)          2,624             117
                                                   ---------       ---------       ---------
    Results of operations after income taxes           1,627          (3,436)            (82)
                                                   ---------       ---------       ---------
Libya
    Revenue -- net of royalties                           --             297           1,005
    Production costs                                      --            (631)         (1,041)
    Depletion and amortization                            --         (11,393)         (5,144)
                                                   ---------       ---------       ---------
    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                      116,992          75,366       $  61,615
    Production costs                                 (17,117)        (19,097)        (17,680)
    Depletion and amortization                       (43,696)        (67,493)        (48,250)
                                                   ---------       ---------       ---------
    Results of operations before income taxes         56,179         (11,224)         (4,315)
    Income tax (expense) recovery                    (20,054)          5,557           2,096
                                                   ---------       ---------       ---------
    Results of operations after income taxes       $  36,125       $  (5,667)      $  (2,219)
                                                   =========       =========       =========
</TABLE>



                                       48
<PAGE>   51

(Unaudited)

CAPITALIZED COSTS RELATING TO GAS AND OIL EXPLORATION AND PRODUCTION ACTIVITIES

<TABLE>
<CAPTION>
December 31,                            2000            1999            1998
-------------------------------      ---------       ---------       ---------
(in thousands)
<S>                                  <C>             <C>             <C>
Proved gas and oil properties        $ 636,939       $ 550,097       $ 475,902
Unproved gas and oil properties         73,163          57,304          76,478
                                     ---------       ---------       ---------
                                       710,102         607,401         552,380
Accumulated depletion                 (383,482)       (339,786)       (266,066)
                                     ---------       ---------       ---------
Net capitalized costs                $ 326,620       $ 267,615       $ 286,314
                                     =========       =========       =========
</TABLE>

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

<TABLE>
<CAPTION>
Year ended December 31,                  2000          1999           1998
---------------------------------      --------      --------       --------
(in thousands)
<S>                                    <C>           <C>            <C>
Property acquisition costs:
    US                                 $  7,789      $  5,352       $  7,903
    UK                                       33            28            115
                                       --------      --------       --------
                                          7,822         5,380          8,018
                                       --------      --------       --------
Purchase of producing properties:
    US                                       --            --            883
Sale of producing properties:
    US                                       --          (155)            --
Exploration costs:
    US                                   57,926        28,753         43,317
    UK                                        9             9             72
    Other foreign                            --         1,531            606
                                       --------      --------       --------
                                         57,935        30,293         43,995
                                       --------      --------       --------
Development costs:
    US                                   36,943        19,542         39,606
    UK                                        1           (39)            71
                                       --------      --------       --------
                                         36,944        19,503         39,677
                                       --------      --------       --------
Total                                  $102,701      $ 55,021       $ 92,573
                                       ========      ========       ========
</TABLE>



                                       49
<PAGE>   52

(Unaudited)

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THERE IN
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. WE THEREFORE CAUTION AGAINST SIMPLISTIC USE OF
THIS INFORMATION.

<TABLE>
<CAPTION>
December 31,                                                                2000              1999              1998
------------------------------------------------------------------      -----------       -----------       -----------
(in thousands)
<S>                                                                     <C>               <C>               <C>
US
    Future cash inflows                                                 $ 2,073,021       $   665,306       $   382,771
    Future production costs                                                (203,058)         (180,948)         (116,976)
    Future development costs                                               (120,262)          (83,476)          (60,203)
    Future income tax expense                                              (539,413)          (63,590)               --
                                                                        -----------       -----------       -----------
    Future net cash flows                                                 1,210,288           337,292           205,592
    Ten percent annual discount for estimated timing of cash flows         (371,192)         (114,871)          (62,089)
                                                                        -----------       -----------       -----------
    Standardized measure of discounted future net cash flows                839,096           222,421           143,503
                                                                        -----------       -----------       -----------
UK
    Future cash inflows                                                      22,809            11,826            19,349
    Future production costs                                                  (3,735)           (8,261)           (7,483)
    Future development costs                                                 (1,469)           (1,397)           (1,457)
    Future income tax expense                                                (4,441)               --                --
                                                                        -----------       -----------       -----------
    Future net cash flows                                                    13,164             2,168            10,409
    Ten percent annual discount for estimated timing of cash flows           (2,795)              (56)           (1,404)
                                                                        -----------       -----------       -----------
    Standardized measure of discounted future net cash flows                 10,369             2,112             9,005
                                                                        -----------       -----------       -----------
Total
    Future cash inflows                                                   2,095,830           677,132           402,120
    Future production costs                                                (206,793)         (189,209)         (124,459)
    Future development costs                                               (121,731)          (84,873)          (61,660)
    Future income tax expense                                              (543,854)          (63,590)               --
                                                                        -----------       -----------       -----------
    Future net cash flows                                                 1,223,452           339,460           216,001
    Ten percent annual discount for estimated timing of cash flows         (373,987)         (114,927)          (63,493)
                                                                        -----------       -----------       -----------
    Standardized measure of discounted future net cash flows            $   849,465       $   224,533       $   152,508
                                                                        ===========       ===========       ===========
</TABLE>



                                       50
<PAGE>   53

(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,                                                      2000            1999            1998
--------------------------------------------------------------------      ---------       ---------       ---------
(in thousands)
<S>                                                                       <C>             <C>             <C>
Sales of oil, ngls and natural gas produced, net of production costs      $(102,732)      $ (61,192)      $ (45,231)
Net change in prices and production costs                                   710,398          83,559         (79,471)
Extensions and discoveries, less related costs                              224,214          83,248          30,159
Purchase of producing properties                                             10,792              --           2,793
Sales of producing properties                                                    --              --              --
Development costs incurred during the period                                 27,828           9,734          23,131
Revisions of previous quantity estimates                                     87,934          (8,441)        (17,191)
Accretion of discount                                                        22,453          15,251          19,958
Net change in income taxes                                                 (330,636)        (41,941)         38,739
Changes in estimated future development costs                               (39,238)        (23,126)        (16,421)
Other                                                                        13,919          14,933          (3,531)
                                                                          ---------       ---------       ---------
Net increase (decrease)                                                     624,932          72,025         (47,065)
Beginning of year                                                           224,533         152,508         199,573
                                                                          ---------       ---------       ---------

End of year                                                               $ 849,465       $ 224,533       $ 152,508
                                                                          =========       =========       =========
</TABLE>



                                       51
<PAGE>   54

(Unaudited)

Quarterly Information

<TABLE>
<CAPTION>
                                                         2000 QUARTER ENDED                         1999 Quarter Ended
                                                -------------------------------------    ------------------------------------------
                                                MAR 31    JUN 30    SEP 30    DEC 31     Mar 31      Jun 30      Sep 30     Dec 31
                                                -------   -------   -------   -------    -------    --------     -------    -------
(in thousands except for per share amounts)
<S>                                            <C>       <C>       <C>       <C>        <C>        <C>          <C>        <C>
FINANCIAL
Revenue                                         $21,224   $24,436   $32,996   $41,217    $13,218    $ 17,543     $22,763    $22,923

Gross profit                                      5,376     8,968    16,352    23,121     (4,169)    (12,491)      3,874        266
Net income (loss)                                 2,105     3,912     8,940    12,391     (3,860)     (8,507)      1,282       (754)
    Per share - basic                              0.13      0.24      0.55      0.77      (0.29)      (0.64)       0.10      (0.05)
              - diluted *                          0.13      0.24      0.51      0.69      (0.29)      (0.64)       0.09      (0.05)

Capital expenditures                            $19,460   $25,493   $21,102   $36,836    $10,389    $  9,337     $16,489    $18,854

Weighted average common shares
   outstanding
    - basic                                      16,224    16,224    16,216    16,068     13,354      13,348      13,349     14,743
    - diluted *                                  16,224    16,404    19,781    19,766     13,354      13,348      13,523     14,743

COMMON SHARE INFORMATION
American Stock Exchange
    Per share - high                            $ 20.38   $ 22.25   $ 22.50   $ 27.75    $ 15.50    $  18.63     $ 22.75    $ 20.38
              - low                               13.38     17.63     15.88     19.31       9.56       12.25       17.44      14.06
              - close                           $ 20.13   $ 19.06   $ 20.69   $ 27.63    $ 12.25    $  17.50     $ 19.00    $ 17.25
    Volume                                        2,924     2,914     3,965     4,424      3,703       2,959       1,872      5,551
Toronto Stock Exchange
    Per share - high                           C$ 27.85  C$ 33.20  C$ 33.50  C$ 41.90   C$ 24.00   C$  26.95    C$ 34.00   C$ 30.25
              - low                               19.50     25.45     23.60     29.20      14.50       19.25       25.90      21.00
              - close                          C$ 27.85  C$ 28.60  C$ 31.00  C$ 41.50   C$ 18.90   C$  25.25    C$ 27.60   C$ 25.00
    Volume                                          483       269       536       599        911         720         413        345
</TABLE>

* Restated to reflect retroactive application of treasury stock method when
  assessing share options for dilutive effect.



                                       52
<PAGE>   55

(Unaudited)

Quarterly Information

<TABLE>
<CAPTION>
                                                2000 QUARTER ENDED                                1999 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>
OPERATING
Daily volumes, before royalties
    Natural gas (mmcf)
        US                             66.1        63.4        77.2        77.6        76.1        74.4        76.7        74.6
        UK                              8.5         5.9         0.3         6.5        11.0         7.7        10.5        10.1
                                     ------      ------      ------      ------      ------      ------      ------      ------
        Total                          74.6        69.3        77.5        84.1        87.1        82.1        87.2        84.7
                                     ======      ======      ======      ======      ======      ======      ======      ======
    Oil and ngls (barrels)            4,154       4,181       3,964       3,792       3,679       5,222       5,200       4,329
    Equivalent (mmcfe)                 99.5        94.3       101.3       106.8       109.2       113.4       118.4       110.7
Daily volumes, after royalties
    Natural gas (mmcf)
        US                             52.9        51.0        62.4        62.4        60.1        59.1        61.4        59.8
        UK                              8.5         5.9         0.3         6.5        11.0         7.7        10.5        10.1
                                     ------      ------      ------      ------      ------      ------      ------      ------
        Total                          61.4        56.9        62.7        68.9        71.1        66.8        71.9        69.9
                                     ======      ======      ======      ======      ======      ======      ======      ======
    Oil and ngls (barrels)            3,494       3,531       3,351       3,208       3,156       4,421       4,394       3,671
    Equivalent (mmcfe)                 82.4        78.1        82.8        88.1        90.1        93.3        98.3        92.0
Pricing
    Natural gas ($ per mcf)
        US                           $ 2.51      $ 3.18      $ 3.84      $ 5.20      $ 1.60      $ 1.97      $ 2.46      $ 2.58
        UK                             1.35        1.58        1.92        3.09        1.13        0.82        0.81        1.03
        Composite                      2.38        3.04        3.83        5.03        1.54        1.86        2.26        2.39
    Oil and ngls ($ per barrel)      $24.06      $26.30      $30.53      $30.32      $10.94      $15.17      $19.31      $21.67
</TABLE>


                                       53



<PAGE>   56

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

There have been no disagreements between us and our auditors on accounting or
financial disclosure matters.


                                    PART III


ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS

Additional information relating to our directors is incorporated herein by
reference from page 6 of our Information Circular dated April 4, 2001 for the
annual and special meeting of shareholders on May 17, 2001.


ITEM 11. EXECUTIVE COMPENSATION

"Executive Compensation" on pages 6 to 10 of our Information Circular dated
April 4, 2001 for the annual and special meeting of shareholders on May 17, 2001
is incorporated herein by reference.


ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

"Voting Shares" and "Share Ownership" on pages 3 and 4 of our Information
Circular dated April 4, 2001 for the annual and special meeting of shareholders
on May 17, 2001 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 30 of this report.


EXHIBITS

Reference is made to the Index to Exhibits on page 55 of this report.


                                       54
<PAGE>   57

                                Index to Exhibits

<TABLE>
<CAPTION>
       Exhibit
       Number          Exhibit
       ------          -------
<S>                    <C>
      *  3 (a)         Articles of Incorporation.
      *  3 (b)         Articles of Amendment.
      *  3 (c)         Articles of Amalgamation.
      *  3 (d)         By-laws number 1 and number 2.
     **  4 (a)         Form of Subordinated Guarantee Agreement.
    ***  4 (b)         Shareholder Rights Plan adopted April 23, 1994.
   **** 10 (a)(i)      Retirement Plan as amended May 15, 1997.
   **** 10 (a)(ii)     Supplementary Retirement Plan as amended March 20, 1997.
  ***** 10 (b)         Share Option Plan as amended March 15, 2000.
      * 10 (c)         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 April 4, 2001 relating to the annual and special meeting of shareholders
                          to be held on May 17, 2001.
 ****** 22             Subsidiaries.
  ***** 24 (a)         Consent of Netherland, Sewell & Associates, Inc.
  ***** 24 (b)         Consent of PricewaterhouseCoopers LLP.
</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.

******* To be filed.



                                       55
<PAGE>   58

                                   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 14, 2001

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

<TABLE>
<S>                                     <C>                                                    <C>
        /s/ D.E. MITCHELL               Director                                               March 14, 2001
----------------------------------
        D.E. Mitchell O.C.

         /s/ S.A. MILNER                President, Chief Executive Officer and                 March 14, 2001
----------------------------------
    S.A. Milner, A.O.E., LL.D.          Director; Principal Executive and Financial Officer

         /s/ S.C. HURLEY                Director                                               March 14, 2001
----------------------------------
           S.C. Hurley

          /s/ H.J. KELLY                Director                                               March 14, 2001
----------------------------------
            H.J. Kelly

         /s/ J.E. MAYBIN                Director                                               March 14, 2001
----------------------------------
           J.E. Maybin

          /s/ L.G. MUNIN                Director                                               March 14, 2001
----------------------------------
            L.G. Munin

         /s/ E.S. ONDRACK               Director                                               March 14, 2001
----------------------------------
           E.S. Ondrack

         /s/ S.T. PEELER                Director                                               March 14, 2001
----------------------------------
           S.T. Peeler

         /s/ R.J. STEFURE               Vice President and Controller                          March 14, 2001
----------------------------------
           R.J. Stefure                 Principal Accounting Officer
</TABLE>

                                       56