U.S. SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549

                                    FORM 40-F

           [_] REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE
                         SECURITIES EXCHANGE ACT OF 1934

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

                  For the fiscal year ended December 31, 2002.


                          COMPTON PETROLEUM CORPORATION
             (Exact name of Registrant as specified in its charter)

<TABLE>
<CAPTION>
<S>                                  <C>                             <C>
  Province of Alberta, Canada                  1311                    Not applicable.
(PROVINCE OR OTHER JURISDICTION OF   (PRIMARY STANDARD INDUSTRIAL     (I.R.S. EMPLOYER
  INCORPORATION OR ORGANIZATION)      CLASSIFICATION CODE NUMBER)    IDENTIFICATION NO.)
</TABLE>

                                   SUITE 3300
                              425-1ST STREET, S.W.
                        CALGARY, ALBERTA, CANADA T2P 3L8
                                 (403) 237-9400
   (ADDRESS AND TELEPHONE NUMBER OF REGISTRANT'S PRINCIPAL EXECUTIVE OFFICES)

                              CT CORPORATION SYSTEM
                   111 EIGHTH AVENUE, NEW YORK, NEW YORK 10011
                                 (212) 894-8400
                     (NAME, ADDRESS (INCLUDING ZIP CODE) AND
                    TELEPHONE NUMBER (INCLUDING AREA CODE) OF
                     AGENT FOR SERVICE IN THE UNITED STATES)

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

                                      None

 Securities registered or to be registered pursuant to Section 12(g) of the Act:

                                      None

              Securities for which there is a reporting obligation
                     pursuant to Section 15(d) of the Act:

                           9.90% Senior Notes due 2009

                 For annual reports, indicate by check mark the
                       information filed with this Form:

        [X] Annual information form    [X] Audited annual financial statements

Indicate the number of outstanding shares of each of the issuer's classes of
capital or common stock as of the close of the period covered by the annual
report:

The Registrant had 116,270,931 Common Shares outstanding at December 31, 2002.

Indicate by check mark whether the Registrant by filing the information
contained in this Form is also thereby furnishing the information to the
Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934
(the "Exchange Act"). If "Yes" is marked, indicate the filing number assigned to
the Registrant in connection with such Rule.

                  Yes           [_]             No              [X]

Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Exchange Act 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              [_]

<PAGE>

                           FORM 40-F TABLE OF CONTENTS


                  DOCUMENT
                  --------

1.                Annual Information Form of the Registrant for the
                  fiscal year ended December 31, 2002.

2.                Management's Discussion and Analysis of the
                  Registrant for the year ended December 31, 2002.

3.                Consolidated Financial Statements of the Registrant
                  for the year ended December 31, 2002, including a
                  reconciliation to United States generally accepted
                  accounting principles.

4.                Election of directors information set forth on pages 1
                  through 2 of the Registrant's Proxy Information Circular
                  dated May 6, 2003.

5.                Exhibits.

<PAGE>

CONSOLIDATED AUDITED ANNUAL FINANCIAL STATEMENTS AND
MANAGEMENT'S DISCUSSION AND ANALYSIS

A.       AUDITED ANNUAL FINANCIAL STATEMENTS

         For consolidated audited financial statements, including the report of
independent chartered accountants with respect thereto, see pages 40 through 70
of the Registrant's 2002 Annual Report attached hereto and included herein. For
a reconciliation of important differences between Canadian and United States
generally accepted accounting principles, see Note 17 of the Notes to the
Consolidated Financial Statements on pages 61 through 70 of such 2002 Annual
Report.

B.       MANAGEMENT'S DISCUSSION AND ANALYSIS

         For management's discussion and analysis, see pages 24 through 39 of
the Registrant's 2002 Annual Report attached hereto and included herein.

         For the purposes of this Annual Report on Form 40-F, only pages 24
through 70 of the Registrant's 2002 Annual Report referred to above shall be
deemed filed, and the balance of such 2002 Annual Report, except as it may be
otherwise specifically incorporated by reference in the Registrant's Annual
Information Form, shall be deemed not filed with the Securities and Exchange
Commission as part of this Annual Report on Form 40-F under the Exchange Act.


CONTROLS AND PROCEDURES

         See Management's Discussion and Analysis of the Registrant for the year
ended December 31, 2002 attached hereto and included herein.

<PAGE>

                  UNDERTAKING AND CONSENT TO SERVICE OF PROCESS

         A.       UNDERTAKING

         The Registrant undertakes to make available, in person or by telephone,
representatives to respond to inquiries made by the Commission staff, and to
furnish promptly, when required to do so by the Commission staff, information
relating to: the securities registered pursuant to Form 40-F; the securities in
relation to which the obligation to file an annual report on Form 40-F arises;
or transactions in said securities.

         B.       CONSENT TO SERVICE OF PROCESS

         A Form F-X signed by the Registrant and its agent for service of
process was filed with the Commission together with the Registrant's
Registration Statement on Form F-4, No. 333-96537.


<PAGE>

                                    SIGNATURE

         Pursuant to the requirements of the Exchange Act, the Registrant
certifies that it meets all of the requirements for filing on Form 40-F and has
duly caused this annual report to be signed on its behalf by the undersigned,
thereto duly authorized.

                                        COMPTON PETROLEUM CORPORATION


May 9, 2003


                                        By: /s/  Norman G. Knecht
                                            ------------------------------------
                                            Name:   Norman G. Knecht
                                            Title:  Vice President, Finance
                                                    and Chief Financial Officer

<PAGE>

                                 CERTIFICATIONS

I, Ernest G. Sapieha, certify that:

1.       I have reviewed this annual report on Form 40-F of Compton Petroleum
         Corporation;

2.       Based on my knowledge, this annual report does not contain any untrue
         statement of a material fact or omit to state a material fact necessary
         to make the statements made, in light of the circumstances under which
         such statements were made, not misleading with respect to the period
         covered by this annual report;

3.       Based on my knowledge, the financial statements, and other financial
         information included in this annual report, fairly present in all
         material respects the financial condition, results of operations and
         cash flows of the registrant as of, and for, the periods presented in
         this annual report;

4.       The registrant's other certifying officer and I are responsible for
         establishing and maintaining disclosure controls and procedures (as
         defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
         we have:

         a)       designed such disclosure controls and procedures to ensure
         that material information relating to the registrant, including its
         consolidated subsidiaries, is made known to us by others within those
         entities, particularly during the period in which this annual report is
         being prepared;

         b)       evaluated the effectiveness of the registrant's disclosure
         controls and procedures as of a date within 90 days prior to the filing
         date of this annual report (the "Evaluation Date"); and

         c)       presented in this annual report our conclusions about the
         effectiveness of the disclosure controls and procedures based on our
         evaluation as of the Evaluation Date;

5.       The registrant's other certifying officer and I have disclosed, based
         on our most recent evaluation, to the registrant's auditors and the
         audit committee of registrant's board of directors (or persons
         performing the equivalent function):

         a)       all significant deficiencies in the design or operation of
         internal controls which could adversely affect the registrant's ability
         to record, process, summarize and report financial data and have
         identified for the registrant's auditors any material weaknesses in
         internal controls; and

         b)       any fraud, whether or not material, that involves management
         or other employees who have a significant role in the registrant's
         internal controls; and

6.       The registrant's other certifying officer and I have indicated in this
         annual report whether or not there were significant changes in internal
         controls or in other factors that could significantly affect internal
         controls subsequent to the date of our most recent evaluation,
         including any corrective actions with regard to significant
         deficiencies and material weaknesses.


Date: May 9, 2003

/s/ Ernest G. Sapieha
-------------------------------------
Ernest G. Sapieha
President and Chief Executive Officer

<PAGE>

I, Norman G. Knecht, certify that:

1.       I have reviewed this annual report on Form 40-F of Compton Petroleum
         Corporation;

2.       Based on my knowledge, this annual report does not contain any untrue
         statement of a material fact or omit to state a material fact necessary
         to make the statements made, in light of the circumstances under which
         such statements were made, not misleading with respect to the period
         covered by this annual report;

3.       Based on my knowledge, the financial statements, and other financial
         information included in this annual report, fairly present in all
         material respects the financial condition, results of operations and
         cash flows of the registrant as of, and for, the periods presented in
         this annual report;

4.       The registrant's other certifying officer and I are responsible for
         establishing and maintaining disclosure controls and procedures (as
         defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
         we have:

         a)       designed such disclosure controls and procedures to ensure
         that material information relating to the registrant, including its
         consolidated subsidiaries, is made known to us by others within those
         entities, particularly during the period in which this annual report is
         being prepared;

         b)       evaluated the effectiveness of the registrant's disclosure
         controls and procedures as of a date within 90 days prior to the filing
         date of this annual report (the "Evaluation Date"); and

         c)       presented in this annual report our conclusions about the
         effectiveness of the disclosure controls and procedures based on our
         evaluation as of the Evaluation Date;

5.       The registrant's other certifying officer and I have disclosed, based
         on our most recent evaluation, to the registrant's auditors and the
         audit committee of registrant's board of directors (or persons
         performing the equivalent function):

         a)       all significant deficiencies in the design or operation of
         internal controls which could adversely affect the registrant's ability
         to record, process, summarize and report financial data and have
         identified for the registrant's auditors any material weaknesses in
         internal controls; and

         b)       any fraud, whether or not material, that involves management
         or other employees who have a significant role in the registrant's
         internal controls; and

6.       The registrant's other certifying officer and I have indicated in this
         annual report whether or not there were significant changes in internal
         controls or in other factors that could significantly affect internal
         controls subsequent to the date of our most recent evaluation,
         including any corrective actions with regard to significant
         deficiencies and material weaknesses.


Date: May 9, 2003

/s/ Norman G. Knecht
----------------------------------
Norman G. Knecht
Vice President, Finance and Chief Financial Officer

<PAGE>

                                  EXHIBIT INDEX

EXHIBIT           DESCRIPTION
-------           -----------

99.1              Consent of Grant Thornton LLP, independent accountants.

99.2              Consent of Outtrim Szabo Associates Ltd., independent
                  engineers.

99.3              Certificate of Principal Executive Officer Pursuant to 18
                  U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the
                  Sarbanes-Oxley Act of 2002.

99.4              Certificate of Principal Financial Officer Pursuant to 18
                  U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the
                  Sarbanes-Oxley Act of 2002.


<PAGE>

                                                                      DOCUMENT 1
                                                                      ----------



                             ANNUAL INFORMATION FORM


                      For the Year Ended December 31, 2002


                          COMPTON PETROLEUM CORPORATION











                                   May 9, 2003

<PAGE>


                                TABLE OF CONTENTS


ABBREVIATIONS...............................................................ii

CONVERSION FACTORS..........................................................ii

FORWARD-LOOKING STATEMENTS...................................................1

CORPORATE STRUCTURE..........................................................1

         NAME AND INCORPORATION..............................................1

GENERAL DEVELOPMENT OF THE BUSINESS..........................................1

         THREE YEAR HISTORY..................................................1

DESCRIPTION OF THE BUSINESS..................................................2

         OVERVIEW............................................................2
         EMPLOYEES...........................................................2
         BUSINESS PLAN AND OPERATING STRATEGY................................2
         PRINCIPAL PROPERTIES................................................3
         PRINCIPAL PRODUCT REVENUE BREAKDOWN.................................5
         SEISMIC.............................................................5
         PRODUCTION HISTORY..................................................5
         DRILLING ACTIVITIES.................................................7
         CRUDE OIL AND NATURAL GAS WELLS.....................................7
         MARKETING...........................................................7
         UNDEVELOPED LAND....................................................8
         RESERVES SUMMARY....................................................8
         RESERVES RECONCILIATION............................................10
         CAPITAL EXPENDITURES...............................................11

SELECTED CONSOLIDATED FINANCIAL INFORMATION.................................11

         DIVIDENDS..........................................................12

MANAGEMENT'S DISCUSSION AND ANALYSIS........................................12

MARKET FOR SECURITIES OF THE CORPORATION....................................12

DIRECTORS AND OFFICERS......................................................13

         DIRECTORS..........................................................13

ADDITIONAL INFORMATION......................................................14


                                      -i-
<PAGE>

                                  ABBREVIATIONS

"BBL" means barrel;

"BBLS" means barrels;

"BCF" means billion cubic feet;

"BOE" means barrels of crude oil equivalent;

"BOEPD" means barrels of crude oil equivalent per day;

"BOPD" means barrels of crude oil per day;

"MBBLS" means thousand barrels;

"MBOE" means thousand barrels of crude oil equivalent;

"MCF" means thousand cubic feet;

"MMBBLS" means million barrels;

"MMBOE" means million barrels of crude oil equivalent;

"MMCF" means million cubic feet;

"MMCFD" means million cubic feet per day;

"MSTB" means thousand stock tank barrels; and

"NGL'S" means natural gas liquids.


                               CONVERSION FACTORS

         To conform with common usage, imperial units of measurement are used in
this Annual Information Form to describe exploration and production.

                1 cubic metre (liquids)            = 6.29 barrels
                1 cubic metre (natural gas)        = 35.31 cubic feet
                1 litre                            = 0.22 imperial gallon
                1 litre                            = 0.26 U.S. gallon



                                      -ii-
<PAGE>


                           FORWARD-LOOKING STATEMENTS

         This Annual Information Form may contain certain forward-looking
statements under the meaning of applicable securities laws. Forward-looking
statements include estimates, plans, expectations, opinions, forecasts,
projections, guidance or other statements that are not statements of fact.
Although Compton Petroleum Corporation ("COMPTON" or the "CORPORATION") believes
that the expectations reflected in such forward-looking statements are
reasonable, it can give no assurance that such expectations will prove to have
been correct. There are many factors that could cause forward-looking statements
not to be correct, including risks and uncertainties inherent in the
Corporation's business. These risks include, but are not limited to: crude oil
and natural gas price volatility, exchange rate fluctuations, availability of
services and supplies, operating hazards and mechanical failures, uncertainties
in the estimates of reserves and in projections of future rates of production
and timing of development expenditures, general economic conditions, and the
actions or inactions of third-party operators. The Corporation's forward-looking
statements are expressly qualified in their entirety by this cautionary
statement.

                               CORPORATE STRUCTURE

NAME AND INCORPORATION

         Compton was incorporated by articles of incorporation pursuant to the
provisions of the BUSINESS CORPORATIONS ACT (Alberta) on October 15, 1992 as
544201 Alberta Ltd. The articles were amended on April 13, 1993 to change the
Corporation's name to Compton Petroleum Corporation and the Corporation
commenced active business operations in July 1993. The articles were amended on
November 21, 1994 and March 1, 1996 in order to remove the private company
restrictions contained in the articles. A further amendment was made to the
articles on September 1, 1998 in order to create a class of preferred shares
issuable in series.

         The Corporation's head and principal office is located at Suite 3300,
425 - 1st Street S.W., Fifth Avenue Place, East Tower, Calgary, Alberta, Canada,
T2P 3L8. Compton's registered office is located at Suite 3000, 237 - 4th Avenue,
S.W., Fifth Avenue Place, West Tower, Calgary, Alberta, Canada, T2P 4X7.

         Effective January 31, 2001, a general partnership called Compton
Petroleum was formed under the laws of Alberta, between Compton and Compton's
wholly owned subsidiary 867791 Alberta Ltd. On July 16, 2001, the partnership
agreement was amended to include Hornet Energy Ltd. Each partner has contributed
a majority of its producing assets to the partnership. The majority of Compton's
production activities are carried out through the partnership.

                       GENERAL DEVELOPMENT OF THE BUSINESS

         Compton is an Alberta-based independent public company actively engaged
in the exploration, development and production of natural gas, ngl's and crude
oil in the Western Canadian Sedimentary Basin (the "WCSB"). The Corporation's
capital stock is listed and trades on the Toronto Stock Exchange (the "TSX")
under the trading symbol "CMT", and is included in both the S&P/TSX Composite
Index and the TSX Mid-Cap Index.

         Compton commenced operations in 1993 with $1 million of share capital,
a small dedicated technical team and a large seismic database. The objective was
to build a company from the grassroots through internal full-cycle exploration,
complemented by strategic acquisitions. Compton's goal was to create a company
capable of long-term sustained growth with a primary focus on natural gas.
Compton's focus and strategy have remained unchanged since conception.

THREE YEAR HISTORY

         In 2000, Compton's operations focused on internally expanding in all of
its core areas. The Corporation incurred approximately $119 million in capital
expenditures, encompassing investment in all phases of the exploration cycle:
land acquisition, seismic, exploratory and development drilling, and
infrastructure improvement. The Corporation drilled 96 gross wells and enhanced
its undeveloped land position by incurring approximately $15 million in land
acquisition expenditures, a majority of which was spent to augment and expand
Compton's working interest land holdings in its southern Alberta core area.


                                      -1-
<PAGE>

         In 2001, Compton continued its focus on exploration and development of
its internally-generated prospects. This focus was also complemented with the
acquisition of Hornet Energy Ltd. in July 2001 for cash consideration of $29.7
million and the assumption of $12.3 million of debt of which $1.4 million was
working capital. This acquisition was strategic to the Corporation as it enabled
Compton to consolidate working interests and obtain operatorship of key
properties within its core area of southern Alberta. The Corporation's 2001
capital program totaled approximately $190 million and the breakdown of this
expenditure program is found on page 11 of this Annual Information Form. In
2001, Compton drilled 95 gross wells with an overall success rate of 76%.

         In 2002, Compton again focused on the continued exploration and
development of its internally-generated prospects. The Corporation's $155
capital program included the drilling of 87 gross wells, with a success rate of
90%. The breakdown of this expenditure is found on page 11 of this Annual
Information Form. Compton's total established reserves increased 19.8 mmboe from
83.7 mmboe to 103.5 mmboe during 2002.

         During 2002, the Corporation also acquired a 50% working interest and
operatorship of a 30 mmcfd gas plant, 95 sections of contiguous undeveloped
lands and 1,911 mboe of established, deep tight natural gas reserves at Callum.
The gas plant currently has 28 mmcfd of unutilized capacity. In December 2002,
Compton expanded its land position at Niton through a swap for 100 sections of
high working interest lands for non-operated minor working interests in the
southern Peace River Arch area.

         The Corporation's success in southern Alberta has resulted in its
processing and gathering facilities operating at maximum capacity. The
Corporation expects these constraints to be resolved by the end of the third
quarter of 2003.

                           DESCRIPTION OF THE BUSINESS

OVERVIEW

         Compton's activities are concentrated principally in three core areas:
southern Alberta in the Centron, Gladys, Okotoks-Mazeppa, High River, Brant,
Hooker, Aphrodite and Callum areas, west-central Alberta in the Bigoray,
Pembina, Niton and Rosevear areas and the Peace River Arch area in north-central
Alberta including the West Rainbow and Zama areas in northern Alberta. Such
areas are a geographic focus of Compton's seismic database and are areas in
which Compton's management ("MANAGEMENT") and staff have significant technical
expertise and operational experience.

EMPLOYEES

         As at December 31, 2002, Compton had 75 full-time employees in its
Calgary office and 25 employees at field locations.

BUSINESS PLAN AND OPERATING STRATEGY

         The Corporation's business plan is to grow Compton's reserves and
maximize production and cash flow from its core geographic areas and other areas
where Compton has technical expertise. Management believes the Corporation is
implementing this objective by aggressively and efficiently exploring,
developing and exploiting its properties, controlling operating costs, adding
economic reserves and production and making strategic acquisitions in its core
areas. Compton has experienced, professional management, technical and support
staff sufficient to carry out its business plan and its current exploration,
exploitation, development, production, engineering, financial and administrative
functions.

         The Corporation's operating strategy includes the components set forth
below.

         CONCENTRATE ON CORE GEOGRAPHIC AREAS. The Corporation has established
and is expanding its core areas within the WCSB. This geographic core area focus
provides Compton with a balanced portfolio of exploration and development
prospects. Compton has in the past developed and continues to develop its
natural gas and crude oil reserves primarily through internal generation of
opportunities. This focus provides the Corporation with the opportunity for high
working interests, which enables Compton to control the timing of capital
expenditures and facilitates the efficient management of its exploration and
development activities. Compton's intention is to generate exploration
opportunities and to significantly increase its undeveloped land base within the
WCSB in this manner.


                                      -2-
<PAGE>

         FOCUS ON NATURAL GAS. Compton has gained considerable technical
expertise and achieved significant success in exploring for deeper and larger,
low-decline natural gas reservoirs. The Corporation plans to continue to focus
on finding and developing long-life natural gas reserves.

         PURSUE FULL-CYCLE EXPLORATION COMPLEMENTED BY SELECTIVE ACQUISITIONS.
The Corporation plans to continue to reinvest internally-generated cash flow to
fund the growth of its exploration prospects and development projects and to
further increase Compton's undeveloped land base in order to maintain a growing
inventory of drilling prospects in its core geographic areas. The Corporation
has also successfully completed and integrated a series of strategic
acquisitions to grow Compton's reserves and production base and enhance the
level of technical expertise in its core areas. Depending on commodity price
cycles, the Corporation may defer exploration projects and enhance its
operations and prospects through strategic acquisitions.

         CONTROL OF INFRASTRUCTURE AND OPERATORSHIP. The Corporation believes
that control over gathering and processing infrastructure and operatorship of
drilling programs will continue to be critical to the success of Compton's
full-cycle exploration program. Compton currently owns or has access to critical
infrastructure in each of its three primary producing areas. Compton operates
approximately 88% of its existing production and, as of December 31, 2002, had a
71% average working interest in its undeveloped lands. This position allows the
Corporation to exercise discretion in determining the timing and methodology of
Compton's ongoing exploration and development programs. The Corporation expects
to continue to expand its position in its core operating areas to maximize
operating efficiencies and maintain control over ongoing capital programs.

         MAINTAIN A LARGE PORTFOLIO OF UNDEVELOPED LAND AND SEISMIC DATABASE.
The Corporation has assembled a significant portfolio of undeveloped land
(working interests in 1,042,923 (742,465 net) acres of undeveloped land, as of
December 31, 2002). Management believes that Compton's existing portfolio of
undeveloped land is sufficient to produce at least five years of
internally-generated exploration and development prospects. In addition to
maintaining a large undeveloped land base, Compton holds a quality,
complementary seismic database. The Corporation's rights to a copy of, and
rights to utilize, extensive seismic data bases of approximately 92,100
kilometres two-dimensional ("2D") seismic and 2,200 square kilometres
three-dimensional ("3D") seismic, concentrated primarily in areas throughout
Compton's core operating areas within Alberta, will continue to be utilized by
Compton to evaluate and generate future prospects and to assist in maintaining
growth of the Corporation.

         MAINTAIN FINANCIAL FLEXIBILITY. The Corporation is committed to
maintaining financial flexibility to allow Compton to pursue its full-cycle
exploration program in periods of low commodity prices. The Corporation also
intends to maintain the flexibility to respond to opportunities for strategic
acquisitions as they arise. Compton has historically funded its exploration and
development capital program through internally-generated cash flow and has
financed acquisitions through debt, the issuance of common shares or a
combination thereof.

PRINCIPAL PROPERTIES

         SOUTHERN ALBERTA

         Compton's primary southern Alberta properties cover an extensive area
from the Calgary city limits and running 250 kilometres south through the
Centron, Gladys, Okotoks-Mazeppa, High River, Brant, Hooker, Aphrodite and
Callum areas. In 1993, the Corporation commenced operations in the Gladys area,
where it is now the largest landowner and operator. The Corporation has expanded
its land and production base in the Centron, Brant, Okotoks-Mazeppa, Hooker,
High River and Callum areas in southern Alberta through property and facility
acquisitions, crown and freehold land purchases, farm-ins and exploration
activities.

         As of December 31, 2002, Compton had working interests in 1,039
sections of land representing 665,236 gross (515,415 net) acres in the southern
Alberta area at an average working interest of 77%. In the Foothills, an
extension of the southern Alberta core area, Compton has a 70% working interest
in 9.4 sections (6,002 acres) of lands to the north of the Stoney Indian
Reservation and 50 kilometres northwest of Calgary. The Corporation also has a
100% working interest in 75 sections of land on the Tsuu T'ina First Nation
Reservation immediately west of Calgary.

         The Corporation has a 50% working interest in a 30 mmcfd gas plant at
Callum and an 8.2% working interest in a 40 mmcfd gas plant at Vulcan. Compton
has a 100% working interest in two oil batteries at Gladys, and Connemara and a
70% working interest in an oil battery at Crossfield. As well, the Corporation
has significant


                                      -3-
<PAGE>

working interests in strategic gathering and compression systems, including a
100% interest at Centron, an 80% interest at Hooker/High River and a 93%
interest at Brant.

         Compton's southern Alberta properties will continue to be a key focus
for the Corporation's exploration, exploitation and development program. Since
inception, Compton has focused on this core area and has secured a large land
base, substantial seismic information, access to, or control over,
infrastructure and processing capacity, high working interests and operatorship.
Having established control in the area, and with several years of
internally-generated prospects in inventory, Management believes Compton is well
positioned to continue to explore, exploit and develop its southern Alberta
properties to their full potential. Compton has focused on multiple natural gas
bearing reservoirs in this area, particularly the Basal Quartz, Crossfield,
Belly River, Ellerslie and the Turner Valley formations.

         WEST-CENTRAL ALBERTA

         In the west-central Alberta region, Compton has an average 48% working
interest in 477,390 gross (228,687 net) acres. The majority of these lands are
located approximately 100 kilometres west of Edmonton in the Bigoray, Pembina,
Niton and Rosevear areas. In Bigoray, production occurs from six light oil
pools, the Nisku D, E and F pools, the Cardium B pool, the Pekisko F pool and
the Ostracod pool. Compton has a 100% interest in an oil battery and compressor
station. The west-central Alberta area provides Compton with excellent
development drilling opportunities and an important balance to the Corporation's
exploration programs in other core areas.

         At Niton, Compton owns a 100% interest in a 10 mmcfd gas plant. At
Rosevear, the Corporation owns a 2% non-operated interest in a 60 mmcfd sour gas
plant. Also at Niton/Rosevear, Compton owns 48,670 net acres of land. The Niton
area is one of increasing focus for the Corporation. Additionally in Central
Alberta, Compton owns and operates a 6 mmcfd gas plant as well as two multi-well
oil batteries at Halkirk.

         The Corporation is pursuing significant additional exploration and
exploitation activities in Compton's working interests in other parts of central
Alberta, including Halkirk, Garrington, Gilby and Wilson Creek to the south and
east of Bigoray.

         PEACE RIVER ARCH, NORTH-CENTRAL AND NORTHERN ALBERTA

         Compton has an average 65% working interest in 294 sections, or 188,000
gross (121,567 net) acres, of land in the Peace River Arch area approximately 20
to 30 kilometres north of Grande Prairie.

         At Cecil, Compton owns various interests in 116 gross (75 net) sections
of land. Production from the property is primarily light oil and natural gas
from the Cecil Charlie Lake "A", "L & MI", "O", "R" and "S" pools. Compton owns
a 40% working interest and a 100% working interest in two multi-well oil
batteries and a 40% working interest in a solution gas plant servicing
production at South Cecil. The Corporation also owns a 40% working interest in a
central battery at Cecil North and owns working interests ranging from 13.9% to
19.5% in the various functional units of the North Cecil Gas Plant. This third
party operated gas plant was placed on stream in April 1998 and is currently
capable of processing 50 mmcfd. A pilot waterflood on the 100% owned Cecil "O"
pool was initiated in December 2002.

         At Worsley, the Corporation owns a 95% working interest in 31 sections
of land, primarily prospective for light oil and natural gas from the Charlie
Lake formation. Compton also owns a 95.27% working interest in a 4 mmcfd
solution gas plant and an 80% working interest in an oil battery. A waterflood
pilot was initiated in June 2002 to optimize oil recovery.

         At Clayhurst, natural gas production is obtained from the four Compton
operated wells. Natural gas is delivered through a 11.4 kilometre sales pipeline
which is 100% owned by the Corporation and which provides strategic control over
a large region that is geographically isolated by river gorges. An extensive
land position consists of 33 net sections of undrilled acreage in this area
proximate to a natural gas gathering system and processing facility which is
operated by Compton. Additional revenue is generated from Compton's processing
of third party gas at Clayhurst.

         In the Progress, Pouce Coupe and Howard areas in the southern most
portion of the Peace River Arch, Compton has extensive wells and landholdings.
Production in the area also occurs from the Doe Creek, Bluesky, Gething,
Cadomin, Charlie Lake, and Montney formations. The Corporation has a 4.96%
working interest in the


                                      -4-
<PAGE>

147 mmcfd Progress Gas Plant and a 21.73% working interest in the Progress
Halfway Unit. The Progress gas plant is also used to process gas from a Pouce
Coupe Montney play being extensively drilled by Compton and its partner.

         The Peace River Arch area offers multizone potential for both
exploration and development opportunities. Specifically, Management believes
Compton's Cecil and Worsley oil properties offer excellent development
opportunities, while Compton's other natural gas properties have multizone
exploration potential. In 2002, Compton completed a swap with a major Canadian
oil company to acquire their operated interest in the Niton area for a
non-operated interest in Sexsmith and Saddlehills fields within the Peace River
Arch.

         The Corporation owns an average 72% working interest in 182 sections,
or 116,495 gross (83,628 net) acres, of land in the West Rainbow and Zama areas
of northern Alberta and British Columbia, as of December 31, 2002.

         The exploration lands in West Rainbow were acquired by Compton to find
and develop natural gas reserves in an area characterized by multiple potential
reservoirs, including the Cretaceous Bluesky, Mississippian zones and the
Devonian, Jean Marie, Sulphur Point, Slave Point and Keg River formations. The
Corporation also has production and exploitation opportunities on its lands to
the north at Zama.

PRINCIPAL PRODUCT REVENUE BREAKDOWN

         The following table sets forth Compton's percentage of revenue for
natural gas and liquids (crude oil and ngl's) that accounted for 15% or more of
Compton's total consolidated revenues for the years ended December 31, 2002 and
2001.

                                         YEARS ENDED DECEMBER 31
                                         -----------------------
                                            2002          2001
                                            ----          ----
Natural Gas                                  74%           72%
Liquids (Crude Oil & Ngl's)                  26            28
TOTAL                                       100%          100%

SEISMIC

         The Corporation owns rights to copies of, and rights to utilize, large
seismic databases for its internal purposes. The proprietary rights of such
databases are owned mostly by third parties (although the proprietary rights of
some databases are owned by the Corporation). These databases include
conventional 2-D seismic covering 92,100 kilometres and 3-D seismic data shot
over 2,200 square kilometres. This data is concentrated primarily in areas
throughout Compton's core operating areas within Alberta. Additionally, the
Corporation has rights to use 6,500 kilometres of seismic covering areas in
southern Manitoba. These large seismic data bases are utilized by the
Corporation's exploration team in exploration and acquisition decisions of the
Corporation.

PRODUCTION HISTORY

         The Corporation's average daily production volume of natural gas and
liquids (crude oil and ngl's), before deduction of royalties, for each of the
periods indicated, is set forth below.

         NATURAL GAS AND LIQUIDS (CRUDE OIL AND NGL'S) PRODUCTION

<TABLE>
<CAPTION>
                                                            FISCAL 2002 THREE MONTHS ENDED
                                               ---------------------------------------------------------
                                                 MARCH 31,     JUNE 30,     SEPTEMBER 30,   DECEMBER 31,      TOTAL
                                                   2002          2002           2002           2002            2002
                                               ---------------------------------------------------------    ---------
<S>                                             <C>           <C>         <C>             <C>               <C>
NATURAL GAS (MMCFD)                                 107.1        109.0           110.2          121.1         111.8
NATURAL GAS (MMCF)                                  9,640        9,919          10,138         11,141        40,838

LIQUIDS (CRUDE OIL & NGL'S) (BOPD)                  6,598        6,610           6,417          6,390         6,503
LIQUIDS (CRUDE OIL & NGL'S)  (MBBLS)                  594          602             590            588         2,374
</TABLE>



                                      -5-
<PAGE>

<TABLE>
<CAPTION>
                                                             FISCAL 2001 THREE MONTHS ENDED
                                                ---------------------------------------------------------
                                                  MARCH 31,     JUNE 30,     SEPTEMBER 30,   DECEMBER 31,      TOTAL
                                                    2001          2001           2001         31, 2001          2001
                                                ---------------------------------------------------------    ---------
<S>                                              <C>           <C>           <C>             <C>             <C>
NATURAL GAS (MMCFD)                                   94.6          96.3           104.1         109.4         101.1
NATURAL GAS (MMCF)                                   8,516         8,763           9,573        10,066        36,918

LIQUIDS (CRUDE OIL & NGL'S) (BOPD)                   6,490         6,497           6,103         7,094         6,546
LIQUIDS (CRUDE OIL & NGL'S) (MBBLS)                    584           591             561           653         2,389
</TABLE>

The Corporation's field netbacks for natural gas and liquids (crude oil and
ngl's), for each of the periods indicated, is set forth below.


         NATURAL GAS AND LIQUIDS (CRUDE OIL AND NGL'S) FIELD NETBACKS


<TABLE>
<CAPTION>
                                                            FISCAL 2002 THREE MONTHS ENDED
                                             ---------------------------------------------------------
                                               MARCH 31,     JUNE 30,     SEPTEMBER 30,   DECEMBER 31,        TOTAL
                                                 2002          2002           2002           2002              2002
                                             ---------------------------------------------------------     -----------
<S>                                            <C>            <C>          <C>             <C>               <C>
NATURAL GAS ($/MCF)
Revenue Price                                  $   2.91       $   3.61     $    3.23       $   4.80          $   3.67
Royalties, net                                    (0.63)         (0.78)        (0.70)         (1.04)            (0.80)
Operating Costs (1)                               (0.78)         (0.85)        (0.84)         (0.83)            (0.83)
                                             ---------------------------------------------------------     -----------
Field Netback                                  $   1.50       $   1.98     $    1.69       $   2.93          $   2.04

LIQUIDS (CRUDE OIL & NGL'S) ($/BBL)
Revenue Price                                  $  24.39       $  30.41     $   30.76       $  32.19          $  29.43
Royalties, net                                    (5.25)         (6.55)        (6.62)         (6.93)            (6.34)
Operating Costs(1)                                (4.69)         (5.13)        (5.05)         (4.98)            (4.96)
                                             ---------------------------------------------------------     -----------
Field Netback                                  $  14.45       $  18.73     $   19.09       $  20.28          $  18.13

<CAPTION>
                                                          FISCAL 2001 THREE MONTHS ENDED
                                             ---------------------------------------------------------
                                              MARCH 31,      JUNE 30,    SEPTEMBER 30,     DECEMBER         TOTAL
                                                 2001          2001           2001         31, 2001         2001
                                             ---------------------------------------------------------     ----------
<S>                                            <C>            <C>          <C>             <C>               <C>
NATURAL GAS ($/MCF)
Revenue Price                                  $  7.93        $ 5.48       $  3.23         $  2.94           $   4.77
Royalties, net                                   (1.68)        (1.42)        (0.66)          (0.78)             (1.11)
Operating Costs (1)                              (0.76)        (0.76)        (0.81)          (0.80)             (0.78)
                                             ---------------------------------------------------------     ----------
Field Netback                                  $  5.49        $ 3.30       $  1.76         $  1.36           $   2.88

LIQUIDS (CRUDE OIL & NGL'S)  ($/BBL)
Revenue Price                                   $33.60        $31.04        $30.37          $21.23          $28.83
Royalties, net                                   (9.80)        (6.04)        (7.53)          (2.31)          (6.29)
Operating Costs(1)                               (4.54)        (4.59)        (4.86)          (4.82)          (4.71)
                                             ---------------------------------------------------------    ----------
Field Netback                                   $19.26        $20.41        $17.98          $14.10          $17.83
</TABLE>

NOTE:
(1)  Operating costs include: field labour and consulting, production equipment
     fuel and chemicals/lubricants, downhole maintenance, freehold mineral
     taxes, gas processing and gathering, repairs and maintenance, field vehicle
     fuel, well testing, utilities and electricity power, hydrocarbon fluid
     hauling, field insurance, property taxes, and miscellaneous operating
     supplies and charges.


                                      -6-
<PAGE>

DRILLING ACTIVITIES

         The following table sets forth the number of crude oil and natural gas
wells drilled by the Corporation, or which the Corporation participated in
drilling, that are capable of production as well as the number of dry and
abandoned wells, all expressed in terms of gross and net wells during the years
ended December 31, 2002 and 2001.

                                              YEARS ENDED DECEMBER 31
                                      -----------------------------------------
                                            2002                 2001
                                      -------------------   -------------------
                                       GROSS(1)    NET(2)    GROSS(1)   NET(2)
                                      -------------------   -------------------
Crude Oil                                  14         12         12         9
Natural Gas                                64         45         60        43
Dry and Abandoned                           9          7         23        19
                                      -----------------------------------------
TOTAL                                      87         64         95        71
                                      =========================================
SUCCESS RATIO                                         90%                  73%

NOTES:
(1)  "Gross" wells refers to all wells in which the Corporation has a
     working interest, or royalty interest, as the case may be.

(2)  "Net" wells refers to the aggregate of the percentage working interest
     of the Corporation in the gross wells before royalties and on a before
     payout basis unless the wells have already paid out.


CRUDE OIL AND NATURAL GAS WELLS

         The following table summarizes the location of the Corporation's
interests, as at December 31, 2002, in crude oil and natural gas wells which are
producing or which the Corporation considers to be capable of production.

<TABLE>
<CAPTION>
                               PRODUCING CRUDE OIL    SHUT-IN CRUDE OIL     PRODUCING NATURAL    SHUT-IN NATURAL GAS
                                      WELLS                WELLS(1)             GAS WELLS              WELLS(1)
                               -------------------    -----------------     -----------------   --------------------
                               GROSS(2)     NET(3)    GROSS(2)   NET(3)     GROSS(2)   NET(3)   GROSS(2)     NET(3)
                               --------     ------    --------   ------     --------   ------   --------     ------
<S>                            <C>          <C>       <C>        <C>        <C>        <C>      <C>         <C>
ALBERTA
         South                    52          25         26         13        246        173       125         95
         Central                 282          72         23         15        180         36       110         20
         Peace River Arch        199          85        363         25        146         68        56         38
                               --------     ------    --------   ------     --------   ------   --------     ------
         TOTAL                   583         182        412         53        572        277       291        153
                               ========     ======    ========   ======     ========   ======   ========     ======
</TABLE>

NOTES:
(1)  "Shut-in" wells are wells which are capable of economic production or
     which the Corporation considers capable of production but which for a
     variety of reasons, including, but not limited to, lack of markets or
     development, are not placed on production at the present time.

(2)  "Gross" wells refers to all wells in which the Corporation has a
     working interest, or royalty interest, as the case may be.

(3)  "Net" wells refers to the aggregate of the percentage working interest
     of the Corporation in the gross wells before royalties and on a before
     payout basis unless the wells have already paid out.

MARKETING

         In 2002, Compton's realized average field prices in Canadian funds were
$3.67 per mcf of natural gas and $29.43 per bbl of liquids (crude oil and
ngl's), as compared to the year 2001 average field prices of $4.77 per mcf and
$28.83 per bbl, respectively.

         Compton's natural gas production is sold under a combination of longer
term contracts with aggregators and short term 30 day AECO indexed contracts.
Approximately 40% of the Corporation's natural gas production in the first three
quarters of 2002 was committed to aggregators, reducing to 18% in the last
quarter as a number of aggregator contracts expired. The average aggregator
price realized was approximately $0.94 per mcf less than the non-aggregator
prices realized during the year.

         Compton's crude oil sales are priced at Edmonton postings and are
typically sold on 30 day evergreen arrangements. Ngl's are bid out on an annual
basis to establish the most competitive pricing. The Corporation sells crude oil
and ngl's primarily to refineries and marketers of crude oil and ngl's.


                                      -7-
<PAGE>

         From time to time, Compton may enter into hedging arrangements to
mitigate commodity price risk and take advantage of opportunistic pricing. In
accordance with Compton's policy, hedging programs will not exceed 50% of
non-contracted production.

UNDEVELOPED LAND

         The following table sets forth the Corporation's undeveloped land
holdings to which no proved reserves have been attributed as at December 31,
2002.
                                              GROSS ACRES(1)     NET ACRES(2)
                                             ---------------   ----------------
British Columbia                                  39,235              10,635
Alberta                                          991,019             719,161
Manitoba                                          12,669              12,669
                                             ---------------   ----------------
TOTAL                                          1,042,923             742,465
                                             ===============   ================

NOTES:
(1)  "Gross" acres refers to the total acres in which the Corporation has an
     interest.

(2)  "Net" acres refers to the total acres in which the Corporation has an
     interest multiplied by the percentage working interest therein owned by
     the Corporation.

RESERVES SUMMARY

         Compton's interests in its natural gas and crude oil properties have
been evaluated in a report (the "REPORT") as at January 1, 2003, prepared by the
independent engineering firm, Outtrim Szabo Associates Ltd. ("OUTTRIM SZABO")
with respect to the properties owned as at December 31, 2002 by Compton. Set
forth below is a summary of the Corporation's crude oil, natural gas and ngl's
reserves and the discounted value of future cash flow therefrom, based upon the
evaluations in the Report.

         ALL EVALUATIONS OF FUTURE CASH FLOW ARE BEFORE INCOME TAXES TO BE
ACCRUED FROM THE SALE OF THE RESERVES AND BEFORE CONSIDERATION OF INDIRECT COSTS
SUCH AS ADMINISTRATIVE OVERHEAD, OTHER MISCELLANEOUS EXPENSES AND INCOME TAXES.
THE PRESENT VALUE OF THE DISCOUNTED FUTURE CASH FLOW CONTAINED IN THE FOLLOWING
TABLES MAY NOT BE REPRESENTATIVE OF THE FAIR MARKET VALUE OF THE RESERVES. THERE
IS NO ASSURANCE THAT THE ESCALATING PRICE AND COST ASSUMPTIONS UPON WHICH THE
TABLES ARE BASED WILL BE ATTAINED. Assumptions and qualifications relating to
costs, prices for future production and other matters are summarized in the
notes to the tables set forth below. Price assumptions are based upon the
average of assumptions made by Outtrim Szabo, as at December 31, 2002. The
Report is based on data supplied by the Corporation and on Outtrim Szabo's
opinions of reasonable practice in the industry.

                      ESCALATED PRICE AND COST ASSUMPTIONS
<TABLE>
<CAPTION>
                                                                                          PRESENT VALUE OF ESTIMATED FUTURE
                                                                                                       CASH FLOW
                        CORPORATE GROSS RESERVES(1)     CORPORATE NET RESERVES(2)              (PRE-TAX) DISCOUNTED AT
                        ---------------------------   -----------------------------   -------------------------------------------
                                   NATURAL                        NATURAL
                        CRUDE OIL    GAS     NGL'S    CRUDE OIL     GAS      NGL'S        0%          10%         15%       20%
                        ---------  -------  -------   ---------   -------   -------   ----------   ---------   --------  --------
                         (MBBLS)   (MMCF)   (MBBLS)    (MBBLS)     (MMCF)   (MBBLS)                (IN THOUSANDS OF $)
<S>                     <C>       <C>       <C>        <C>      <C>        <C>        <C>          <C>         <C>       <C>
Proved reserves:(3)

Producing(4)              5,447   289,010     5,487      4,672   223,715     4,018     1,155,234     531,947    437,405   376,566

Non-producing(5)          1,203    86,381     1,659        936    66,404     1,245       314,531     173,467    145,844   125,763

Undeveloped(6)              778    26,638       578        598    20,300       415        82,755      61,738     48,860    39,545
                        -------  --------   -------    -------  --------   -------    ----------   ---------   --------  --------
TOTAL PROVED              7,428   402,029     7,723      6,206   310,419     5,678     1,552,520     767,152    632,109   541,874

Probable additional
reserves(7)               6,539   190,844     4,343      5,071   145,024     3,160       739,594     282,277    208,255   160,836
                        -------  --------   -------    -------  --------   -------    ----------   ---------   --------  --------

TOTAL BEFORE RISK        13,967   592,873    12,066     11,277   455,443     8,837     2,292,114   1,049,429    840,364   702,710

Reduction for risk(8)    (3,270)  (95,422)   (2,171)    (2,536)  (72,512)   (1,580)     (369,797)   (141,139)  (104,128)  (80,418)
                        -------  --------   -------    -------  --------   -------    ----------   ---------   --------  --------

TOTAL PROVED PLUS
PROBABLE ADDITIONAL
RESERVES                 10,698   497,451     9,895      8,742   382,931     7,257     1,922,317     908,291    736,237   622,292
                        =======  ========   =======    =======  ========   =======    ==========   =========   ========  ========
</TABLE>


*NOTE:  AMOUNTS MAY NOT ADD EXACTLY DUE TO ROUNDING.


                                      -8-
<PAGE>

                       CONSTANT PRICE AND COST ASSUMPTIONS
<TABLE>
<CAPTION>
                                                                                         PRESENT VALUE OF ESTIMATED FUTURE
                                                                                                      CASH FLOW
                        CORPORATE GROSS RESERVES(1)     CORPORATE NET RESERVES(2)             (PRE-TAX) DISCOUNTED AT
                        ---------------------------   -----------------------------  ---------------------------------------------
                                   NATURAL                        NATURAL
                        CRUDE OIL    GAS     NGL'S    CRUDE OIL     GAS      NGL'S       0%          10%         15%         20%
                        ---------  -------  -------   ---------   -------   -------  ----------   ---------   ---------   --------
                         (MBBLS)   (MMCF)   (MBBLS)    (MBBLS)     (MMCF)   (MBBLS)               (IN THOUSANDS OF $)
<S>                     <C>        <C>      <C>       <C>        <C>        <C>      <C>          <C>         <C>         <C>
Proved reserves:(3)

Producing(4)               5,438   288,952    5,487     4,657     226,635    4,005    1,376,961     697,361     576,418    496,180

Non-producing(5)           1,197    86,254    1,659       930      67,201    1,241      388,306     230,779     194,194    167,500

Undeveloped(6)               778    26,638      577       589      20,665      411      136,695      91,202      73,190     60,174
                         -------  --------  -------   -------    --------  -------   ----------   ---------   ---------  ---------
TOTAL PROVED               7,414   401,844    7,722     6,176     314,501    5,656    1,901,962   1,019,342     843,802    723,854
Probable additional
reserves (7)               6,532   190,775    4 342     5,025     146,995    3,150      929,898     405,909     307,839    243,263
                         -------  --------  -------   -------    --------  -------   ----------   ---------   ---------  ---------

TOTAL BEFORE RISK         13,946   592,619   12,065    11,201     461,496    8,806    2,831,860   1,425,251   1,151,641   967,117

Reduction for risk(8)     (3,266)  (95,388)  (2,171)   (2,513)    (73,498)  (1,575)    (464,949)   (202,955)   (153,920)  (121,632)
                         -------  --------  -------   -------    --------  -------   ----------   ---------   ---------  ---------

TOTAL PROVED PLUS
PROBABLE ADDITIONAL
RESERVES                  10,680   497,232    9,893     8,688     387,999    7,231    2,366,911   1,222,297     997,722    845,486
                         =======  ========  =======   =======     ======== =======   ==========   =========   =========  =========
</TABLE>

*NOTE:  AMOUNTS MAY NOT ADD EXACTLY DUE TO ROUNDING.

NOTES:

(1)   "Gross reserves" means those reserves accruing to the Corporation before
      deduction of all royalties.

(2)   "Net reserves" means those reserves accruing to the Corporation after
      deduction of all royalties and interests owned by others.

(3)   "Proved reserves" means those reserves estimated as recoverable under
      current technology and anticipated economic conditions for the escalated
      dollar economics and existing economic conditions for the constant dollar
      economics, from that portion of a reservoir which can be reasonably
      evaluated as economically productive on the basis of analysis of drilling,
      geological, geophysical and engineering data, including the reserves to be
      obtained by enhanced recovery processes demonstrated to be economical and
      technically successful in the subject reservoir.

(4)   "Proved producing reserves" means those developed reserves that are
      actually on production or, if not producing, that could be recovered from
      existing wells or facilities and where the reason for the current
      non-producing status is the choice of the owner rather than the lack of
      markets or some other reasons. An illustration of such a situation is
      where a well or zone is capable of production but is shut-in because its
      deliverability is not required to meet contract requirements.

(5)   "Proved non-producing reserves" means those developed reserves that are
      not currently producing either due to lack of facilities and/or markets.

(6)   "Proved undeveloped reserves" means proved 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.
      Reserves on undrilled acreages are limited to those drilling units
      offsetting productive units, which are reasonably certain of production
      when drilled.

(7)   "Probable additional reserves" means those reserves which analysis of
      drilling, geological, geophysical and engineering data does not
      demonstrate to be proved under current technology and anticipated economic
      conditions for the escalated dollar economics and existing economic
      conditions for the constant dollar economics, but where such analysis
      suggests the likelihood of their existence and future recovery. Probable
      additional reserves to be obtained by the application of enhanced recovery
      processes will be the increased recovery over and above that estimated in
      the proved category which can be realistically estimated for the pool on
      the basis of enhanced recovery processes which can be reasonably expected
      to be instituted in the future.

(8)   Corporate reserves and estimated future net reserves derived therefrom are
      reduced for risk by 50 percent of the probable additional reserves to
      account for the probability of obtaining production from such reserves.

(9)   All values are shown in Canadian dollars.

(10)  Discounted present values of estimated future cash flow as set forth in
      the table above, ESCALATED PRICE AND COST ASSUMPTIONS, are based upon
      price assumptions as set out below. The price assumptions are based upon
      the assumptions made by the independent engineering firm, Outtrim Szabo,
      as at December 31, 2002. The reference base price forecasts and cost
      escalation used in the escalating price case are set out below:

<TABLE>
<CAPTION>
                           CRUDE OIL                  NATURAL GAS                               NGL'S
                          -----------  -----------------------------------------   --------------------------------
                           EDMONTON
              YEAR          PAR 40     AECO-C SPOT  TRANSCANADA GAS  PAN-ALBERTA    PROPANE     BUTANE    PENTANES+
         --------------   ----------   -----------  ---------------  -----------   ---------   --------   ---------
                           ($/BBL)       ($/MCF)       ($/MCF)        ($/MCF)       ($/BBL)    ($/BBL)     ($/BBL)
<S>        <C>            <C>          <C>          <C>              <C>           <C>         <C>        <C>
              2003           39.73         5.66          5.35           4.60         21.85       23.84      40.12
              2004           35.56         5.07          4.82           4.22         21.34       23.12      35.92
              2005           32.88         4.63          4.44           3.99         19.73       21.37      33.21
              2006           33.37         4.65          4.53           4.23         20.02       21.69      33.70
              2007           33.87         4.68          4.61           4.46         20.32       22.02      34.21
              2008           34.38         4.72          4.72           4.72         20.63       22.35      34.72
              2009           34.89         4.77          4.77           4.77         20.94       22.68      35.24
              2010           35.42         4.83          4.83           4.83         21.25       23.02      35.77
</TABLE>


                                      -9-
<PAGE>

<TABLE>
<CAPTION>
                           CRUDE OIL                  NATURAL GAS                               NGL'S
                          -----------  -----------------------------------------   --------------------------------
                           EDMONTON
              YEAR          PAR 40     AECO-C SPOT  TRANSCANADA GAS  PAN-ALBERTA    PROPANE     BUTANE    PENTANES+
         --------------   ----------   -----------  ---------------  -----------   ---------   --------   ---------
                           ($/BBL)       ($/MCF)       ($/MCF)        ($/MCF)       ($/BBL)    ($/BBL)     ($/BBL)
<S>        <C>            <C>          <C>          <C>              <C>           <C>         <C>        <C>
              2011           35.95         4.88          4.88           4.88         21.57       23.37      38.31
              2012           36.49         4.94          4.94           4.94         21.89       23.72      36.85
              2013           37.04         5.02          5.02           5.02         22.22       24.07      37.41
              2014           37.59         5.13          5.13           5.13         22.55       24.43      37.97
              2015+   *Crude Oil, Natural Gas and Ngl's prices are escalated
                       at 1.5% per year thereafter.
</TABLE>

(11)  Product prices in the constant price evaluation are the following:
           o Crude Oil - $48.24 per bbl
           o Natural Gas - $6.02 per mcf o Ngl's - $27.86 per bbl
           o Butane - $33.66 per bbl
           o Pentane - $47.18 per bbl

           The constant price assumptions assume the continuance of current
           laws, regulations and operating costs in effect on the date of the
           Report.

(12)  The Report estimates the total capital costs net to the Corporation
      necessary to achieve the estimated future net proved and probable
      production revenues, based on the escalated cost assumptions, to be $140.0
      million including $25.9 million relating to well costs net of salvage
      value with $61.1 million, $52.2 million and $5.1 million of such costs to
      be incurred in fiscal years 2003, 2004, and 2005, respectively.

(13)  The Report estimates the total capital costs net to the Corporation
      necessary to achieve the estimated future net proved and probable
      production revenues, based on constant price assumptions, to be $134.3
      million including $21 million relating to well abandonment costs net of
      salvage value with $61.1 million, $51.4 million and $5.0 million of such
      costs to be incurred in the fiscal years 2003, 2004 and 2005,
      respectively.

(14)  The $U.S./$Cdn exchange rate is to be $0.64 in 2003, $0.64 in 2004, $0.64
      in 2005, and held constant at $0.64 thereafter.

(15)  A portion of the Corporation's reserves qualifies to receive the Alberta
      Royalty Tax Credit (the "ARTC"). The ARTC was assumed in the Report to
      continue under the current program or an extension thereof for a period of
      10 years.

(16)  Salvage values for facilities and abandonment costs have been assumed to
      offset each other.

RESERVES RECONCILIATION

         The following tables provide a summary of the changes in the
Corporation's reserves, upon escalated price and cost assumptions, before
applicable royalties, which occurred in the most recent fiscal year.

         CRUDE OIL AND NGL'S RESERVES RECONCILIATION

<TABLE>
<CAPTION>
                                                       PROVED          50% OF PROBABLE          TOTAL
                                                  ---------------    -------------------   ---------------
                                                       (MBBL)               (MBBL)               (MBBL)
<S>                                               <C>                <C>                   <C>
AS AT DECEMBER 31, 2001                                13,083                3,751              16,834
Development, exploration & exploitation                 3,656                1,136               4,792
Acquisitions / (Dispositions), net                        660                  405               1,065
Reserve Revisions                                         126                  149                 275
Production                                             (2,373)                  --              (2,373)
                                                  ---------------    -------------------   ---------------
AS AT DECEMBER 31, 2002                                15,152                5,441              20,593
                                                  ===============    ===================   ===============
<CAPTION>

         NATURAL GAS RESERVES RECONCILIATION


                                                       PROVED           50% OF PROBABLE          TOTAL
                                                  ---------------     ------------------    --------------
                                                       (MMCF)                (MMCF)               (MMCF)
<S>                                               <C>                 <C>                   <C>
AS AT DECEMBER 31, 2001                               352,023                49,023              401,046
Development, exploration & exploitation                72,070                31,200              103,270
Acquisitions / (Dispositions), net                     11,454                 3,679               15,133
Reserve Revisions                                       7,290                11,520               18,810
Production                                            (40,808)                   --              (40,808)
                                                  ---------------     ------------------    --------------
AS AT DECEMBER 31, 2002                               402,029                95,422              497,451
                                                  ===============     ==================    ==============
</TABLE>


                                      -10-
<PAGE>

CAPITAL EXPENDITURES

         The tables set forth below summarize the capital expenditures made by
the Corporation on natural gas and crude oil properties and facilities for the
periods indicated.

<TABLE>
<CAPTION>
                                                        FISCAL 2002 THREE MONTHS ENDED
                                            -------------------------------------------------------
            (IN THOUSANDS OF $)               MARCH 31,    JUNE 30,    SEPTEMBER 30,   DECEMBER 31,          TOTAL
                                                 2002        2002           2002           2002               2002
                                            ----------- ------------ --------------- --------------      -----------
<S>                                         <C>           <C>          <C>            <C>                <C>
Land and seismic                               $5,201         $843         $5,711         $17,341           $29,096
Development, exploration and exploitation      11,247       11,855         22,959          29,308            75,369
Plant and production facilities                 3,208        6,698          6,645           5,163            21,714
Acquisitions / (Dispositions), net                215        3,350          2,950          22,414            28,929
                                            ----------- ------------ --------------- --------------      -----------
Sub-total                                     $19,871      $22,746        $38,265         $74,226          $155,108
Acquisitions, Corporate                            --           --             --              --                --
                                            ----------- ------------ --------------- --------------      -----------
TOTAL                                         $19,871      $22,746        $38,265         $74,226          $155,108
                                            =========== ============ =============== ==============      ===========
</TABLE>

<TABLE>
<CAPTION>
                                                        FISCAL 2002 THREE MONTHS ENDED
                                            -------------------------------------------------------
            (IN THOUSANDS OF $)               MARCH 31,   JUNE 30,    SEPTEMBER 30,   DECEMBER 31,          TOTAL
                                                 2002       2002           2002           2002               2002
                                            ----------- ------------ --------------- --------------      -----------
<S>                                         <C>           <C>          <C>            <C>                <C>
Land and seismic                             $ 4,689     $ 9,273        $11,261            $660          $ 25,883
Development, exploration and exploitation     23,507      12,502         15,810          32,839            84,658
Plant and production facilities                5,955       7,797          6,254           7,637            27,643
Acquisitions / (Dispositions), net             3,060      12,727         (2,857)         (2,687)           10,243
                                            ---------- ------------ --------------- ---------------     -----------
Sub-total                                    $37,211     $42,299        $30,468         $38,449          $148,427
Acquisitions, Corporate                           --          --         42,040              --            42,040
                                            ---------- ------------ --------------- ---------------     -----------
TOTAL                                        $37,211     $42,299        $72,508         $38,449          $190,467
                                            ========== ============ =============== ===============     ===========
</TABLE>


                   SELECTED CONSOLIDATED FINANCIAL INFORMATION

         The following table sets forth certain financial information of the
Corporation for the last three fiscal years.

<TABLE>
<CAPTION>
                                                            YEARS ENDED DECEMBER 31
                                             ---------------------------------------------------
                                                2002                 2001                2000
                                             ----------          ----------          -----------
                                                  (IN THOUSANDS OF $ EXCEPT PER SHARE DATA)
<S>                                           <C>                <C>                 <C>
Total net revenue (after royalties)           172,240              189,051             168,681
Earnings before tax                            38,993               79,214              76,656
Earnings                                       18,798               55,636              40,059
Earnings per share                               0.17                 0.51                0.37
Earnings per share (diluted)                     0.16                 0.48                0.36
Total assets                                  817,272              693,973             524,272
Total long term debt                          300,760              230,449             183,376
</TABLE>

         Effective January 1, 1999 and January 1, 2000, respectively, the
Corporation wound-up Compton Energy and Compton Oil & Gas. Under the terms of
the wind-up, all the assets and properties of the subsidiaries were transferred
to the Corporation and the Corporation assumed all of their liabilities and
obligations. Combined operations continue in the single corporate entity,
Compton Petroleum Corporation. The majority of Compton's production activities
are carried out through Compton Petroleum, a general partnership formed
effective January 31, 2001. See "Corporate Structure- Name and Incorporation".

         The Canadian Institute of Chartered Accountants ("CICA") has approved a
new standard for the computation, presentation and disclosure of per share
amounts. In the fourth quarter of 2000, the Corporation retroactively adopted
the new standard. Under this standard, the treasury stock method is used instead
of the


                                      -11-
<PAGE>

imputed earnings method to determine the dilutive effect of stock options,
warrants and other dilutive instruments. Under the treasury stock method only
"in the money" dilutive instruments impact the dilution calculations. Prior
period diluted earnings per share and cash flow from operations per share have
been restated for this change in accounting policy.

         Effective January 1, 2000, the Corporation adopted the new
recommendations of the CICA with respect to accounting for future income taxes.
Under the new recommendations, the liability method of tax allocation is used,
which is based upon the difference between financial and tax bases of assets and
liabilities. Previously, the deferred method was used which was based upon
differences between the timing of reporting income and expenses for financial
and income tax purposes. The Corporation has adopted this change in accounting
policy retroactively, without restating the financial statements of prior
periods. As a result, the Corporation recorded a reduction in retained earnings
of $0.4 million, an increase in property and equipment of $68.1 million and an
increase in the future income tax liability, previously the deferred income tax
liability of $68.5 million, as at January 1, 2000. The adjustments were mainly
the result of future tax costs relating to acquisitions where the tax basis
acquired was less than the purchase price, and the tax consequence of
flow-through share issues.

         During the fourth quarter of 2001, the Corporation adopted early the
new recommendations of the CICA with respect to accounting for Stock-based
Compensation. The Corporation has adopted this accounting policy retroactively,
without restating the financial statements of prior periods. As a result, the
Corporation recorded a reduction in retained earnings of $3.6 million, an
increase in accounts payable of $6.2 million and a decrease in future income tax
liability of $2.6 million. CICA Handbook section 3870 "Stock-based Compensation"
establishes financial accounting and reporting standards for stock-based
employee compensation plans as well as transactions in which an entity issues
its equity instruments to acquire goods or services from non-employees. The
Corporation has elected to follow the intrinsic value method of accounting for
stock-based compensation arrangements. Since all options were granted with an
exercise price equal to the market price at the date of the grant, no
compensation cost has been charged to income at the time of the option grants.

DIVIDENDS

         The Corporation has neither declared nor paid any dividends on its
common shares. The Corporation intends to retain its earnings to finance growth
and expand its operations and does not anticipate paying any dividends on its
common shares in the foreseeable future.

                      MANAGEMENT'S DISCUSSION AND ANALYSIS

         For Management's Discussion and Analysis of Financial Condition see
pages 24 to 39 of the Corporation's 2002 Annual Report, such pages being
incorporated by reference into this Annual Information Form.

                    MARKET FOR SECURITIES OF THE CORPORATION

         All the outstanding common shares of the Corporation are listed and
posted for trading on the Toronto Stock Exchange under the symbol "CMT".
Compton's common shares are included in the S&P/TSX Composite Index and the TSX
Mid-Cap Index.

                             DIRECTORS AND OFFICERS

DIRECTORS

         Information is given below with respect to each of the current
directors of the Corporation. All directors of Compton stand for election at
each annual meeting of the Corporation. The next Annual and Special Meeting of
Shareholders is scheduled for June 3, 2003 at 3:30 pm. (Calgary time) in The
Historical Ballroom, Calgary Chamber of Commerce, 517 Centre Street South,
Calgary, Alberta, Canada.

         The board of directors has established an Audit, Finance and Risk
Committee, an Engineering, Environmental, Health and Safety Committee and a
Governance and Compensation Committee. Each of these committees consists of all
directors of the Corporation, other than Mr. Sapieha, each of whom is
independent and unrelated to the Corporation and its affiliates.


                                      -12-
<PAGE>

<TABLE>
<CAPTION>
NAME AND MUNICIPALITY
OF RESIDENCE                                             PRINCIPAL OCCUPATION                       DIRECTOR SINCE
--------------------------------------------------------------------------------------------------------------------
<S>                                       <C>                                                       <C>
Mel F. Belich, Q.C.(1)                    President of Enbridge International Inc. and Group             1993
Calgary, Alberta                          Vice President, International & Corporate Law,
                                          Enbridge Inc., an energy transportation and
                                          distribution company; prior to September 1, 2000,
                                          Senior Vice President, International Development &
                                          General Counsel for Enbridge Inc.; and prior to
                                          July 1, 1999 Senior Vice President & General
                                          Counsel for Enbridge Inc.

Irvine J. Koop, P. Eng.(2)                Chairman and Chief Executive Officer, IKO
Calgary, Alberta                          Resources Inc.; prior to May 2001, Executive Vice
                                          President and President and Chief Executive
                                          Officer, Pipelines and Midstream, Westcoast Energy             1996
                                          Inc., an energy products and services company.

John W. Preston                           Account Executive, Sun Microsystems of Canada                  1993
Calgary, Alberta                          Inc., a computer company.

Jeffrey T. Smith, P. Geol.(3)             Independent Businessman; prior to 1998, Chief
Calgary, Alberta                          Operating Officer of Northstar Energy Corporation,             1999
                                          an oil and gas company.

Ernest G. Sapieha, C.A.                   President & Chief Executive Officer of the                     1993
Calgary, Alberta                          Corporation.
</TABLE>

NOTES:
(1)  Chairman of the Corporation and Chairman of the Governance and Compensation
     Committee.

(2)  Chairman of the Audit, Finance and Risk Committee.

(3)  Chairman of the Engineering, Environmental, Health and Safety Committee.

         Further information about the directors and the committees of the board
of directors is set forth under the heading "Election of Directors" on pages 1
to 2 of the Corporation's Proxy Information Circular dated May 6, 2003 relating
to the Annual and Special Meeting of Shareholders to be held on June 3, 2003,
which sections are incorporated by reference into this Annual Information Form.

OFFICERS

         The name, city of residence and principal occupation during the last
five years of each of the officers of the Corporation are set forth in the
following table.

<TABLE>
<CAPTION>
NAME AND MUNICIPALITY
OF RESIDENCE                                              PRINCIPAL OCCUPATION
-------------------------------------------------------------------------------------------------
<S>                                        <C>
Ernest G. Sapieha, C.A.                    President & Chief Executive Officer of the
Calgary, Alberta                           Corporation.

Norman G. Knecht, C.A.                     Vice President Finance & Chief Financial Officer
Calgary, Alberta                           of the Corporation.

Tim G. Millar                              Vice President, General Counsel & Corporate
Calgary, Alberta                           Secretary of the Corporation; prior to 2003,
                                           Senior Partner of Fraser Milner Casgrain LLP,
                                           Barristers and Solicitors.

Murray J. Stodalka, P. Eng.                Vice President, Engineering & Operations of the
Calgary, Alberta                           Corporation.

Kim N. Davies, P.Geoph.                    Vice President, New Ventures, prior to 2003, Vice
Calgary, Alberta                           President, Exploration of the Corporation.

Marc R. Junghans                           Vice President, Exploration, prior to 2003,
Calgary, Alberta                           Manager of Exploration of the Corporation.
</TABLE>

         As at May 5, 2003, the directors and officers of Compton as a group
beneficially owned or controlled, directly or indirectly, 14,719,019 common
shares of Compton, representing approximately 10.3% of the issued and
outstanding common shares of the Corporation on a fully diluted basis.


                                      -13-
<PAGE>

                             ADDITIONAL INFORMATION

         The Corporation will provide to any person, upon request to the Chief
Financial Officer of the Corporation at the address listed below, the following
additional information:

         (a)      when the Corporation is in the course of a distribution of its
                  securities pursuant to a short form prospectus or when a
                  preliminary short form prospectus has been filed in respect of
                  a distribution of its securities:

                  (i)    one copy of the Corporation's annual information form
                         together with one copy of any document, or the
                         pertinent pages of any document, incorporated by
                         reference in the annual information form;

                  (ii)   one copy of the comparative financial statements of the
                         Corporation for its most recently completed financial
                         year together with the accompanying report of the
                         auditor and one copy of any interim financial
                         statements of the Corporation subsequent to the most
                         recently completed financial year;

                  (iii)  one copy of the information circular of the Corporation
                         in respect of its most recent annual meeting of
                         shareholders that involved the election of directors or
                         one copy of any annual filing prepared instead of that
                         information circular, as appropriate; and

                  (iv)   one copy of any other document that is incorporated by
                         reference into the short form prospectus or the
                         preliminary short form prospectus and that is not
                         required to be provided under (i), (ii) or (iii) above;

         (b)      at any other time, one copy of any other document referred to
                  in (a)(i), (ii) and (iii) above, provided that the Corporation
                  may require the payment of a reasonable charge if the request
                  is made by a person who is not a holder of the Corporation's
                  securities.

         Additional information including directors' and officers' remuneration
and indebtedness, principal holders of the Corporation's common shares, options
to acquire common shares and interests of insiders in material transactions (if
applicable) is contained in the Proxy Information Circular issued by Management
dated May 6, 2003, relating to the Annual and Special Meeting of Shareholders to
be held on June 3, 2003. Additional financial information is also provided in
the comparative financial statements of the Corporation for the year ended
December 31, 2002 included in the Corporation's 2002 Annual Report. Copies of
these documents and additional copies of this Annual Information Form are
available to the public and may be obtained by contacting:

                 Compton Petroleum Corporation
                 Suite 3300, 425 - 1st Street S.W.
                 Fifth Avenue Place, East Tower
                 Calgary, Alberta, Canada
                 T2P 3L8
                 Attention:   Mr. Norman G. Knecht, C.A.
                              Vice President Finance & Chief Financial Officer
                 Telephone:   (403) 237-9400
                 Fax:         (403) 237-9410.


                                      -14-
<PAGE>

                                                                      DOCUMENT 2
                                                                      ----------


MANAGEMENT'S DISCUSSION AND ANALYSIS


------------------------------------------------------
TABLE OF CONTENTS

Overview                                           24
Results of Operations                              25
Consolidated Financial Results                     29
Accounting Policies                                35
2003 Outlook                                       37
Business Conditions, Risk and Risk Management      38
Management's Report                                40
Independent Auditors' Report                       41
Consolidated Financial Statements                  42
Notes to the Consolidated Financial Statements     45
Supplemental Reserve Information                   71
------------------------------------------------------


OVERVIEW

MANAGEMENT'S DISCUSSION AND ANALYSIS IS A REVIEW OF THE COMPANY'S 2002 FINANCIAL
AND OPERATING RESULTS AND SHOULD BE READ IN CONJUNCTION WITH THE AUDITED
CONSOLIDATED FINANCIAL STATEMENTS AND RELATED NOTES FOR THE YEAR ENDED DECEMBER
37,2002. THE CONSOLIDATED FINANCIAL STATEMENTS HAVE BEEN PREPARED IN ACCORDANCE
WITH CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES ("GAAP"). A
RECONCILIATION TO UNITED STATES GAAP IS INCLUDED IN NOTE 17 TO THE CONSOLIDATED
FINANCIAL STATEMENTS.

PER BOE AMOUNTS HAVE BEEN CALCULATED USING A CONVERSION RATE OF 6,OOO CUBIC FEET
OF NATURAL GAS BEING EQUIVALENT TO ONE BARREL OF CRUDE OIL. MANAGEMENT'S
DISCUSSION AND ANALYSIS MAY CONTAIN CERTAIN FORWARD-LOOKING STATEMENTS UNDER THE
MEANING OF APPLICABLE SECURITIES LAWS. FORWARD-LOOKING STATEMENTS INCLUDE
ESTIMATES, PLANS, EXPECTATIONS, OPINIONS, FORECASTS, PROJECTIONS, GUIDANCE OR
OTHER STATEMENTS THAT ARE NOT STATEMENTS OF FACT. ALTHOUGH COMPTON PETROLEUM
CORPORATION ("COMPTON" OR THE "COMPANY") BELIEVES THAT THE EXPECTATIONS
REFLECTED IN SUCH FORWARD-LOOKING STATEMENTS ARE REASONABLE, IT CAN GIVE NO
ASSURANCE THAT SUCH EXPECTATIONS WILL PROVE TO HAVE BEEN CORRECT. THERE ARE MANY
FACTORS THAT COULD CAUSE FORWARD-LOOKING STATEMENTS NOT TO BE CORRECT, INCLUDING
RISKS AND UNCERTAINTIES INHERENT IN THE COMPANY BUSINESS. THESE RISKS
INCLUDE, BUT ARE NOT LIMITED TO: CRUDE OIL AND NATURAL GAS PRICE VOLATILITY,
EXCHANGE RATE FLUCTUATIONS, AVAILABILITY OF SERVICES AND SUPPLIES, OPERATING
HAZARDS AND MECHANICAL FAILURES, UNCERTAINTIES IN THE ESTIMATES OF RESERVES AND
IN PROJECTIONS OF FUTURE RATES OF PRODUCTION AND TIMING OF DEVELOPMENT
EXPENDITURES, GENERAL ECONOMIC CONDITIONS, AND THE ACTIONS OR INACTIONS OF
THIRD-PARTY OPERATORS. THE COMPANY'S FORWARD-LOOKING STATEMENTS ARE
EXPRESSLY QUALIFIED IN THEIR ENTIRETY BY THIS CAUTIONARY STATEMENT.

MANAGEMENT'S DISCUSSION AND ANALYSIS CONTAINS THE TERM "CASH FLOW FROM
OPERATIONS"; WHICH SHOULD NOT BE CONSIDERED AN ALTERNATIVE TO, OR MORE
MEANINGFUL THAN "CASH FLOW FROM OPERATING ACTIVITIES" AS DETERMINED IN
ACCORDANCE WITH CANADIAN GAAP AS AN INDICATOR OF THE COMPANY'S FINANCIAL
PERFORMANCE. COMPTON'S DETERMINATION OF CASH FLOW FROM OPERATIONS MAY NOT BE
COMPARABLE TO THAT REPORTED BY OTHER COMPANIES. THE OTHER ITEMS REQUIRED TO
ARRIVE AT CASH FLOW FROM OPERATING ACTIVITIES ARE CONSIDERED TO BE CORPORATE
CHARGES.

Compton is an independent public company actively engaged in the exploration,
development, and production of natural gas, natural gas liquids, and crude oil
in Western Canada. The Company's activities are concentrated in three core
geographic areas in Alberta. Compton's growth and reserves base have resulted
from exploration and development activities complemented by


24
<PAGE>

strategic acquisitions. The Company is committed to long-term sustainable growth
through a focus on natural gas with deeper, long-life, low-decline reserves.

RESULTS OF OPERATIONS

UNDEVELOPED LAND

During 2002, Compton continued to expand its land base within its core operating
areas. Undeveloped land increased by 6 percent to 742,465 net (1,042,923 gross)
acres, from 700,695 net (962,259 gross) acres in 2001. The Company has an
average 71 percent working interest in this large land base, sufficient to
generate a minimum of five years of drilling prospects.

Compton's landholdings are as follows:

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------
                                                   ACRES                      SECTIONS
AREA                                       GROSS           NET          GROSS           NET
--------------------------------------------------------------------------------------------
<S>                                     <C>            <C>              <C>           <C>
Southern Alberta                         473,501       372,871            740           583
Central Alberta                          275,108       168,107            430           263
Peace River Arch                         135,200        96,018            211           150
Northern Alberta                         107,210        82,165            168           128
Other                                     51,904        23,304             81            36
--------------------------------------------------------------------------------------------
December 31, 2002 total                1,042,923       742,465          1,630         1,160
--------------------------------------------------------------------------------------------
December 31, 2001 total                  962,259       700,695          1,504         1,095
December 31, 2000 total                  763,503       610,640          1,193           954
--------------------------------------------------------------------------------------------
</TABLE>

ACQUISITIONS

During the fourth quarter of 2002, the Company completed two strategic land and
facility acquisitions. At Callum, immediately south and west of Hooker in
Southern Alberta, the Company acquired a 50 percent working interest and
operatorship of a 30 mmcf per day natural gas plant, 95 sections of contiguous
undeveloped lands and 1.9 million boe of established, deep tight natural gas
reserves. The undeveloped acreage is prospective for deep tight natural gas
targets and is an expansion of Compton's core area in Southern Alberta.

At Niton, in West Central Alberta, Compton expanded its land position by
swapping loo sections of high workinginterest lands, wells and facilities for
non-operated minor working interests in the southern Peace River Arch. The Niton
lands contain primarily multi-zone natural gas reserves and include a 100%
interest in a 10mmcf per day gas plant.

CAPITAL EXPENDITURES

The Company continued to invest in land, seismic, production facilities and
exploratory drilling necessary for future value creation. In 2002, drilling and
completions accounted for 48 percent of capital expenditures of $155 million.
The remaining 52 percent of capital expenditures were split amongst land,
facilities and property acquisitions, similar to 2001.


                                                                              25
<PAGE>

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------
                                               2002                 2001                2000
CAPITAL EXPENDITURES                    ($000S)        %    ($000S)        %    ($000S)        %
-------------------------------------------------------------------------------------------------
<S>                                    <C>           <C>   <C>           <C>   <C>           <C>
Drilling and completions                75,369        48    84,658        44    66,695        56
Land and seismic                        29,096        19    25,883        14    23,241        20
Facilities                              21,714        14    27,643        15    27,901        24
Acquisitions, net                       28,929        19    22,614        11       635        --
-------------------------------------------------------------------------------------------------
Subtotal                               155,108       100   160,798        84   118,472       100
Corporate acquisitions                      --        --    29,669        16        --        --
-------------------------------------------------------------------------------------------------
Tota1                                  155,108       100   190,467       100   118,472       100
-------------------------------------------------------------------------------------------------
</TABLE>

DRILLING ACTIVITY

In 2002, consistent with the Company's strategy of internal prospect generation
and full-cycle exploration, Compton drilled a total of 87 gross wells, compared
to 95 gross wells in 2001. In 2001,48 percent of wells drilled were exploratory
and 52 percent were development. In 2002, of the 87 wells drilled, 35 percent
were classified as exploratory wells and 65 percent were classified as
development wells.

Compton's 2002 drilling program achieved an overall success rate of 9o percent.
Drilling results are summarized below:

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------
                           NATURAL
                             GAS          OIL         D&A        TOTAL        NET        SUCCESS
--------------------------------------------------------------------------------------------------
<S>                            <C>          <C>          <C>        <C>         <C>         <C>
AREA
Southern Alberta               51           0            7          58          46          88%
Central Alberta                 3           2            1           6           4          83%
Peace River Arch               10          12            1          23          14          96%
--------------------------------------------------------------------------------------------------
2002 total                     64          14            9          87          64          90%
--------------------------------------------------------------------------------------------------
2001 total                     60          12           23          95          71          76%
2000 total                     56          10           30          96          78          70%
--------------------------------------------------------------------------------------------------
</TABLE>

Compton's natural gas targets continue to be deeper than the typical Alberta
well. The average well depth of the Company's 2002 drilling program was
approximately 1,789 metres (5,869 feet). Compton's deep drilling technical
expertise and its large land base enable the Company to explore for and develop
larger reservoirs with long-life, low-decline reserves.

RESERVES

Compton's proven reserves increased by 15 percent to 82.2 million boe at
December 31, 2002 from 71.8 million boe at December 31, 2001. Total proven
reserves comprised 79 percent of the Company's established reserves at December
31, 2002 compared to 86 percent at year-end 2001. As a result of successful
development activities, proven undeveloped reserves were moved to the proven
producing and non-producing categories and decreased by approximately 2.2
million boe. Proven undeveloped reserves comprised only 7 percent of total
proven reserves at December 31, 2002 compared to 11 percent of proven reserves
at December 31, 2001. Risked probable reserves increased by 79 percent to 21.3
million boe at December 31, 2002 further illustrating the extensive development
opportunities existing within the Company.


26
<PAGE>

In 2002, Compton focused on the continued development of its
internally-generated prospects, with 76 percent of 2002 reserves additions
generated through drilling activities. Overall, natural gas comprised 82 percent
of the Company's proven reserves (8o percent of established). On a 10 percent
discounted cash flow basis, the established value of reserves increased by 35
percent to $908.3 million at December 31, 2002 from $672.3 million at December
31, 2001.

The Company's reserves were evaluated by independent petroleum engineering
consultants, Outtrim Szabo and Associates Ltd. and were reviewed by an
independent committee of Compton's Board of Directors. A summary of the report
is presented below:

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------
RESERVES AT                         NATURAL     CRUDE OIL      TOTAL OIL                    DISCOUNTED CASH FLOW
DECEMBER 31, 2002                     GAS        AND NGLS      EQUIVALENT      % OF       10% DCF        15% DCF
ESCALATING ECONOMICS                 (BCF)       (MBBLS)      (MBOE) (6:1)    TOTAL       ($000S)        ($000S)
-----------------------------------------------------------------------------------------------------------------
<S>                                   <C>         <C>           <C>              <C>     <C>            <C>
Proven
     Producing                        289         10,934        59,102           57      531,947        437,405
     Non-producing                     86          2,862        17,259           17      173,467        145,844
     Undeveloped                       27          1,356         5,795            6       61,737         48,860
-----------------------------------------------------------------------------------------------------------------
Total proven                          402         15,152        82,156           80      767,151        632,109
     Risked probable                   95          5,441        21,345           20      141,139        104,127
-----------------------------------------------------------------------------------------------------------------
Established                           497         20,593       103,501          100      908,290        736,236
-----------------------------------------------------------------------------------------------------------------
</TABLE>

The value of oil and natural gas reserves is based upon commodity price
assumptions at January 1, 2003 and reflects a per barrel oil price (Edmonton
Light) of $39.73 (WTI: US$26.00) for 2003, decreasing to $32.88 (WTI: US$21.00)
in 2005, and then escalating to $37.59 (WTI: US$24.74) in 2014, and 1.5 percent
per year thereafter. Natural gas pricing is based upon an Alberta spot price of
$5.66 per mcf in 2003, declining to $4.63 in 2005 and then escalating to $5.13
in 2014 and 1.5 percent per year thereafter.

RESERVE RECONCILIATION

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------
                                                CRUDE OIL AND NGLS                         NATURAL GAS
--------------------------------------------------------------------------------------------------------------------
                                                          50%                                   50%
                                             PROVEN   PROBABLE        TOTAL       PROVEN     PROBABLE        TOTAL
                                             (MBBLS)    (MBBLS)      (MBBLS)        (BCF)        (BCF)        (BCF)
--------------------------------------------------------------------------------------------------------------------
<S>                                        <C>           <C>         <C>             <C>           <C>         <C>
December 31, 2001                          13,083        3,751       16,834          352           49          401
Development, exploration
     and exploitation                       3,656        1,136        4,792           72           31          103
Acquisitions, net                             660          405        1,065           11            4           15
Reserve revisions                             126          149          275            7           11           18
Production                                 (2,373)           0       (2,373)         (40)           0          (40)
--------------------------------------------------------------------------------------------------------------------
December 31, 2002                          15,152        5,441       20,593          402           95          497
--------------------------------------------------------------------------------------------------------------------
</TABLE>

EFFICIENCY MEASURES

Compton's 2002 finding and development ("F&D") costs are among the best in the
industry. Reserve additions for 2002 were achieved at an all-in F&D cost of
$7.92 per boe on a proven basis and $5.35 per boe established. On a five-year
average basis, which is more reflective of full-cycle exploration, F&D costs are
$7.59 per boe proven and $6.30 per boe established.


                                                                              27
<PAGE>

The recycle ratio is used as an indicator of the efficiency with which an
exploration and production company can replace its produced reserves. As such,
the recycle ratio is widely accepted as a measure of value creation. In 2002,
Compton generated an established recycle ratio of 1.9 times.

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
                                                                                             AVERAGE
-----------------------------------------------------------------------------------------------------------
                                            2002        2001         2000            3 YEAR        5 YEAR
-----------------------------------------------------------------------------------------------------------
<S>                                         <C>         <C>          <C>               <C>           <C>
Proven reserve additions
     F&D costs ($/boe)                      7.92        9.88         8.67              8.84          7.59
     Recycle ratio                          1.3         1.5          1.8               1.5           1.6
     Reserve replacement ratio              2.0         2.3          1.8               2.1           2.6
Established reserve additions
     F&D costs ($/boe)                      5.35        9.90         7.11              7.15          6.30
     Recycle ratio                          1.9         1.5          2.2               1.9           2.0
     Reserve replacement ratio              3.2         2.3          2.2               2.6           3.2
-----------------------------------------------------------------------------------------------------------
</TABLE>

RESERVE LIFE INDEX

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------
                              NATURAL  CRUDE OIL     2002 OIL       2001 OIL      2000 OIL
(Years)                         GAS     AND NGLS    EQUIVALENT     EQUIVALENT    EQUIVALENT
--------------------------------------------------------------------------------------------
<S>                           <C>            <C>          <C>            <C>           <C>
Proven                         9.9           6.4           8.9           7.8           7.5
Established                   12.2           8.7          11.2           9.1           9.0
--------------------------------------------------------------------------------------------
</TABLE>

Compton's 2002 reserve life index is 8.9 years proven and 11.2 years
established, further illustrating the long life of the Company's reserves.

NET ASSET VALUE

The Company's net asset value as at December 31, 2002 was $6.48 per common
share, based upon established reserves (escalated dollar pricing) discounted at
10 percent. The Company's 2002 established reserves increased by 24 percent,
contributing to an increase of 33 percent in net asset value from December 31,
2001.

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------
($millions, except per share amounts)                         2002          2001          2000
------------------------------------------------------------------------------------------------
<S>                                                         <C>            <C>           <C>
Oil and natural gas reserves, established, 10% DCF            908.3         672.3         678.8
Undeveloped land and seismic                                  110.0         100.7          98.4
Other                                                           3.6           2.8           1.6
------------------------------------------------------------------------------------------------
                                                            1,021.9         775.8         778.8

Corporate debt, net                                          (268.5)       (208.3)       (153.4)
------------------------------------------------------------------------------------------------
Net asset value                                               753.4         567.5         625.4
------------------------------------------------------------------------------------------------

Net asset value per share, issued and outstanding              6.48          5.02          5.75
------------------------------------------------------------------------------------------------
</TABLE>



28
<PAGE>

PRODUCTION

Compton's production profile continues to reflect the Company's focus on natural
gas which accounted for approximately 74 percent of 2002 production. Compton's
natural gas production averaged 112 mmcf per day in 2002, an increase of 11
percent from 2001. Liquids production decreased by 1 percent to 6,503 barrels
per day from 6,546 barrels per day in 2001. On a boe basis, production for 2002
averaged 25,137 boe per day, a 7 percent increase from 23,404 boe per day in
2001.

Production for 2003 is expected to increase by approximately 11 percent over
2002, based upon the Company's 2003 capital expenditures program of $171
million.

The Company's success in Southern Alberta has resulted in processing and
gathering facilities currently operating at maximum capacity. Operational
constraints were experienced at the Mazeppa gas plant in the fourth quarter of
2002 as the plant had not previously operated at maximum capacity and due to the
high liquids content of natural gas from Hooker. These problems have generally
been resolved.

Compton is actively pursuing expansion of the Mazeppa plant by adding an
additional 30 mmcf per day capacity by the third quarter of 2003. Additional
plans are underway to offload Brant production to an alternative sales pipeline
by the end of the second quarter in 2003, adding 15 mmcf per day capacity.

To further address temporary processing constraints, Compton acquired a 50
percent interest in a 30 mmcf per day natural gas processing plant (28 mmcf per
day current unutilized capacity) in the fourth quarter of 2002. Also included in
the purchase were 1.9 million boe of established reserves, 1 mmcfe per day of
net production and a 50 percent interest in 95 contiguous sections of
undeveloped lands in the Callum area of southern Alberta. Compton intends to
build a pipeline from Aphrodite to the Callum plant by the fourth quarter of
2003.

CONSOLIDATED FINANCIAL RESULTS

CASH FLOW AND NET EARNINGS

Cash flow from operations in 2002 was $96.5 million ($0.85 per share basic), a
25 percent decrease from 2001 cash flow from operations of $128.3 million ($1.17
per share basic). Net earnings for the year totalled $18.8 million ($0.17 per
share basic), a 66 percent decrease from the $55.6 million ($0.51 per share
basic) earned in 2001. The Company's 2002 cash flow and net earnings benefited
from increased production volumes; however, the results were affected by lower
realized commodity prices. Net earnings included a net loss of $1.6 million
related to an unrealized foreign exchange loss due to the translation of the
Company's U.S. dollar seven-year notes.


                                                                              29
<PAGE>

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------
              NETBACKS                                      2002                            2001            2000
--------------------------------------------------------------------------------------------------------------------
                                                       CRUDE OIL AND
            ($/BOE @ 6:I)               NATURAL GAS         NGLS
--------------------------------------------------------------------------------------------------------------------
                                          ($/MCF)          ($/BBL)          ($/BOE)         ($/BOE)         ($/BOE)
--------------------------------------------------------------------------------------------------------------------
<S>                                           <C>            <C>             <C>             <C>             <C>
Revenue                                       3.67           29.43           23.95           28.68           28.54
Royalties, net                               (0.86)          (5.18)          (5.17)          (6.55)          (5.98)
Operating expenses                           (0.83)          (4.96)          (4.96)          (4.71)          (4.22)
--------------------------------------------------------------------------------------------------------------------
Field operating netback                       1.98           19.29           13.82           17.42           18.34
--------------------------------------------------------------------------------------------------------------------
General and administrative                                                   (1.07)          (0.74)          (0.79)
Interest expense                                                             (2.19)          (1.51)          (1.71)
Capital taxes                                                                (0.17)          (0.16)          (0.12)
--------------------------------------------------------------------------------------------------------------------
Cash flow netback                                                            10.39           15.01           15.72
--------------------------------------------------------------------------------------------------------------------
</TABLE>

QUARTERLY INFORMATION

The following table sets forth certain quarterly financial information of the
Company for the last two fiscal years:

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
($000s, except per share data)                                FISCAL 2002 THREE MONTHS ENDED
-----------------------------------------------------------------------------------------------------------
                                                    MARCH 31,        JUNE 30,       SEPT. 30,       DEC. 31,
                                                        2002            2002            2002           2002
-----------------------------------------------------------------------------------------------------------
<S>                                                  <C>             <C>             <C>            <C>
Total revenue                                         42,548          54,018          50,889         72,332
Earnings before tax                                    6,406          18,325          (6,434)        20,696
Earnings                                               3,472          11,026           1,447          2,853
Earnings per share (basic)                              0.03            0.10            0.01           0.03
Earnings per share (diluted)                            0.03            0.09            0.01           0.02
Total assets                                         700,533         717,496         751,773        817,272
Total long-term debt                                 230,000         250,586         261,740        260,634
-----------------------------------------------------------------------------------------------------------

-----------------------------------------------------------------------------------------------------------
($000s, except per share data)                                Fiscal 2002 Three Months Ended
-----------------------------------------------------------------------------------------------------------
                                                    March 31,        June 30,       Sept. 30,      Dec.  31,
                                                        2001            2001            2001           2001
-----------------------------------------------------------------------------------------------------------
Total revenue                                         87,197          66,415          47,927         43,431
Earnings before tax                                   40,793          26,743          11,004          5,621
Earnings                                              19,526          27,485           3,593          2,267
Earnings per share (basic)                              0.20            0.26            0.07           0.02
Earnings per share (diluted)                            0.19            0.24            0.07           0.02
Total assets                                         549,488         569,815         653,310        693,973
Total long-term debt                                 182,000         182,000         230,371        230,000
-----------------------------------------------------------------------------------------------------------
</TABLE>



30
<PAGE>

REVENUE AND PRICING

Compton realized $219.8 million in petroleum and natural gas revenue in 2002, a
decrease of 10 percent from $245.0 million generated the previous year. The
decrease in revenue resulted from lower natural gas prices realized in 2002 than
in 2001, despite increased production in 2002. The Company's average 2002
realized oil and natural gas liquids price increased by 2 percent from 2001 to
$29.43 per boe. In 2002, Compton's average realized natural gas price was $3.67
per mcf, down 23 percent from the 2001 average of $4.77 per mcf.

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------
Revenue ($000s)                       2002                      2001                       2000
-----------------------------------------------------------------------------------------------------
                               $            %            $             %            $            %
<S>                          <C>            <C>        <C>             <C>        <C>            <C>
Natural gas                  148,133        67         174,424         71         141,367        67
Natural gas hedging            1,789         1           3,666          1               0         0
Crude oil and ngls            70,297        32          68,880         28          79,664        37
Crude oil hedging               (432)        0               0          0          (7,655)       (4)
-----------------------------------------------------------------------------------------------------
Revenue                      219,787       100         244,970        100         213,376       100
-----------------------------------------------------------------------------------------------------
</TABLE>

MARKETING

In 2002, the Company's realized average field prices in Canadian funds were
$3.67 per mcf of natural gas and $29.43 per barrel of crude oil and natural gas
liquids, compared to the 2001 average field prices of $4.77 per mcf and $28.83
per barrel.

Compton's natural gas production is sold under a combination of longer-term
contracts with aggregators and short-term 30-day AECO-indexed contracts.
Approximately 40 percent of the Company's natural gas production in the first
three-quarters of 2002 was committed to aggregators, reducing to 18 percent in
the last quarter as a number of aggregator contracts expired. The average
aggregator price realized was approximately $0.94 per mcf less than the
non-aggregator prices realized during the year. The fourth-quarter aggregator
price was $1.12 per mcf lower than non-aggregator prices.

Compton's crude oil sales are priced at Edmonton postings and are typically sold
on 30-day evergreen arrangements. Natural gas liquids are bid out on an annual
basis to establish the most competitive pricing.The Company sells crude oil and
natural gas liquids primarily to refineries and marketers of crude oil and
natural gas liquids.

From time to time, Compton may enter into hedging arrangements to mitigate
commodity price risk. In accordance with Compton's policy, hedging programs will
not exceed 50 percent of non-contracted production. See Risk Mitigation
discussion on page 39 for outstanding hedges.



                                                                              31
<PAGE>

ROYALTIES

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------
($000s, except where noted)                   2002              2001             2000
--------------------------------------------------------------------------------------
<S>                                         <C>               <C>               <C>
Crown royalties                             38,902            44,075            39,159
Other royalties                              9,095            12,344             6,188
--------------------------------------------------------------------------------------
                                            47,997            56,419            45,347
Alberta Royalty Tax Credit                    (500)             (500)             (652)
--------------------------------------------------------------------------------------
Net royalties                               47,497            55,919            44,695

Percentage of revenue                        21.6%             22.8%             20.9%
--------------------------------------------------------------------------------------
</TABLE>

The Company's royalty obligations for 2002, net of the Alberta Royalty Tax
Credit, amounted to $47.5 million, a decrease of 15 percent from the previous
year. This decrease is attributable to lower revenues in 2002 and the effects of
the provincial sliding-scale Crown royalty structure, which imposes lower
royalty rates at lower commodity prices. The average royalty rate on total
production was 21.6 percent in 2002, compared to 22.8 percent in the preceding
year.

         OPERATING EXPENSES

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------
                                              2002              2001              2000
--------------------------------------------------------------------------------------
<S>                                         <C>               <C>               <C>
Operating expenses ($000s)                  45,546            40,222            31,571
Operating expenses per boe ($/boe)            4.96              4.71              4.22
--------------------------------------------------------------------------------------
</TABLE>

Operating expenses totalled $45.5 million in 2002. On a unit-of-production
basis, operating costs were $4.96 per boe compared to $4.71 per boe during the
same period in 2001, an increase of 5 percent year-over-year. The general
increase in the cost of goods and services in the oil and natural gas industry,
together with increased field staff levels and higher energy costs, contributed
to the Company's higher operating costs on a unit-of-production basis.

GENERAL AND ADMINISTRATIVE EXPENSES

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------
($000S, except where noted)                   2002              2001             2000
--------------------------------------------------------------------------------------
<S>                                         <C>                 <C>              <C>
Gross G&A expense                           13,456               9,805            8,094
Operating recoveries                        (3,611)             (3,503)          (2,179)
--------------------------------------------------------------------------------------
Net G&A expense                              9,845               6,302            5,915
Net G&A expense per boe ($/boe)               1.07                0.74             0.79
--------------------------------------------------------------------------------------
</TABLE>



32
<PAGE>

In 2002, the Company's general and administrative ("G&A") expenses totalled $9.8
million, compared to $7.8 million for the preceding year before a recovery of
$1.5 million relating to stock-based compensation. On a boe basis, G&A costs
were $1.07, an increase of 18 percent from the $0.91 incurred in 2001.
Additional full-time employees required due to the expanded activities of the
Company and increased insurance expense contributed to increased G&A in 2002.

In 2001, the Company adopted the new recommendations of the Canadian Institute
of Chartered Accountants ("CICA") with respect to stock-based compensation. As a
result, the Company recorded a recovery of $1.5 million of non-management
employee stock-based compensation costs in 2001 resulting in net G&A expense of
$6.3 million for 2001.


INTEREST EXPENSES

--------------------------------------------------------------------------------
($000S)                                       2002          2001          2000
--------------------------------------------------------------------------------

Interest expense                            20,130        12,863        12,772
Average debt outstanding                   265,605       203,410       153,815
--------------------------------------------------------------------------------

The Company's interest expense in 2002 totalled $20.1 million compared to $12.9
million for the previous year. The increased interest expense is attributable to
higher debt servicing costs associated with the long-term U.S. notes issue and
includes $1.7 million of non-cash charges.


DEPLETION, DEPRECIATION AND SITE RESTORATION COSTS

The Company's depletion and depreciation expense, which includes a provision for
the future costs of site restoration and abandonment, increased to $56.0 million
from $50.5 million in 2001. The average cost in 2002 was $6.10 per boe, slightly
higher than $5.91 per boe in 2001.

On an annual basis, Compton reviews its liability for future site restoration
and abandonment costs. For 2002, the provision totalled $1.1 million compared to
$0.7 million in 2001. Current costs for site restoration and abandonments, net
of recoveries, were estimated at approximately $18.8 million, of which $2.2
million is reflected as an accumulated provision in the December 31, 2002
consolidated balance sheet.


TAXES

CAPITAL TAX

Compton is liable for the payment of federal Large Corporations Tax ("LCT"). In
2002, the LCT increased to $1.4 million from $1.3 million in 2001, due to an
increase in the Company's capital base upon which the LCT is calculated. This
tax is non-deductible and increases as the capital resources of the Company
increase.

FUTURE INCOME TAX EXPENSE

The Company's future income taxes were $18.8 million in 2002 compared to $22.2
million in 2001. The 2002 expense is lower due to a combination of decreased
earnings and lower resource allowance in 2002.


                                                                              33
<PAGE>

TAX POOLS

Compton has approximately $274.4 million of tax pools at January 1, 2003. The
following table summarizes the Company's estimated tax pool balances by
classification:

-------------------------------------------------------------------------------
                                                                MAXIMUM
                                                AVAILABLE        ANNUAL
                                                 BALANCE       DEDUCTION
-------------------------------------------------------------------------------
                                                ($000s)

Canadian exploration expense                       352             100%
Canadian development expense                    48,996              30%
Canadian oil and gas property expense          145,812              10%
Undepreciated capital cost                      79,265              20%-30%
-------------------------------------------------------------------------------
Total                                          274,425
-------------------------------------------------------------------------------


LIQUIDITY AND CAPITAL RESOURCES

The capitalization of the Company at December 31, 2002 consisted primarily of
$245.8 million of shareholders' equity and US$165 million senior term notes.
Total debt outstanding at year-end, net of working capital, was $268.6 million.
Working capital at December 31, 2002 was $32.1 million compared to $22.2 million
in 2001, an increase of $9.9 million principally due to a higher cash balance at
December 31, 2002 compared to December 31, 2001.

Compton expects funds generated from operations, together with available funds
under the Company's existing bank credit facilities, will be sufficient to
finance current operations and planned capital expenditures for 2003.

DEBT

In May 2002, the Company issued US$165 million of 9.90 percent senior notes due
2009. The senior notes are unsecured and were issued at a price per note of
98.273 percent. The net proceeds from the offering were approximately US$157.2
million, which the Company used to repay its entire existing bank indebtedness
and for general corporate purposes.

At December 31, 2002 the Company had drawn $4o million of its syndicated credit
facility; $128 million remains available. The senior notes offering, the
subsequent repayment of the Company's outstanding bank indebtedness and
available line of credit enhances Compton's financial flexibility and
facilitates its continuing strategy for long-term sustainable growth.

EQUITY

In December 2002, Compton completed a private placement of 3,085,175
flow-through common shares for total gross proceeds of approximately $17.6
million. The funds were utilized to fund the expansion of Compton's exploration
operations.

In March 2002, Compton obtained regulatory approval from the Toronto Stock
Exchange to repurchase a maximum of 5.4 million of the Company's outstanding
common shares for cancellation. The repurchase program was approved for a
12-month period, which commenced on March 8, 2002 and ended on March 7, 2003 and
it was subsequently renewed in 2003 for a further 12-month period. For the year
ended December 31, 2002, the Company repurchased 796,200 common shares under
this program at an average cost of $3.80 per share.



34
<PAGE>

ACCOUNTING POLICIES

The application of Canadian GAAP involves certain assumptions, judgements and
estimates that affect reported amounts of assets, liabilities, revenues and
expenses. The basis for these estimates is historical experience and various
other assumptions that management believes to be reasonable. These estimates are
the basis for making judgements about the carrying value of assets and
liabilities. Actual results could differ from these estimates under different
assumptions or conditions. Thus, the application of these principles can produce
varying results from company to company.

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

The Chief Executive Officer and Chief Financial Officer evaluated the
effectiveness of the Company's disclosure controls and procedures as of a date
within 90 days of the filing of the report (the "Evaluation Date"), and
concluded that, as of the Evaluation Date, the Company's disclosure controls and
procedures are effective to ensure that information required to disclose in its
filings with the Securities and Exchange Commission under the Securities
Exchange Act of 1934 is recorded, processed, summarized and reported, within the
time periods specified in the Commission's rules and forms, and to ensure that
information required to be disclosed in the reports that it files under the
Exchange Act is accumulated and communicated to the Company's management,
including its Chief Excecutive Officer and Chief Financial Office, as
appropriate to allow timely decisions regarding required disclosure.

CHANGES TO INTERNAL CONTROLS AND PROCEDURES FOR FINANCIAL REPORTING

There were no significant changes to Compton's internal controls or in other
factors that could significantly affect these controls subsequent to the
Evaluation Date and the filing date of the Annual Report.

FULL COST ACCOUNTING

Compton follows the full cost method of accounting for petroleum and natural gas
operations. Under this accounting method, all costs related to the exploration
for and development of petroleum and natural gas reserves are capitalized.
Capitalized costs, as well as the estimated future expenditures to develop
proven reserves, are depleted using the unit-of-production method based on
estimated proven oil and natural gas reserves.

CEILING TEST

In applying the full cost method, Compton calculates a ceiling test whereby the
carrying value of petroleum and natural gas properties and production equipment,
net of recorded future income taxes and the accumulated provision for site
restoration and abandonment costs, is compared annually to an estimate of future
net cash flow from the production of proven reserves. Net cash flow is estimated
using year-end prices, less estimated future general and administrative
expenses, financing costs and income taxes. Should this comparison indicate an
excess carrying value, the excess is charged against earnings as additional
depletion and depreciation.

OIL AND NATURAL GAS RESERVES

All of Compton's oil and natural gas reserves are evaluated and reported on by
independent petroleum engineering consultants. The estimation of reserves is a
subjective process. Forecasts are based on engineering data, projected future
rates of production and the timing of future expenditures, all of which are
subject to numerous uncertainties and various interpretations. The Company
expects that its estimates of reserves


                                                                              35
<PAGE>

will change to reflect updated information. Reserve estimates can be revised
upward or downward based on the results of future drilling, testing or
production levels.

Proven oil and natural gas reserves are those reserves that geological and
engineering data demonstrate with reasonable certainty can be recovered in
future years from known reservoirs under existing economic and operating
conditions. Probable additional reserves are those reserves not currently
demonstrated to be proven under existing economic and operating conditions, but
where analysis suggests the likelihood of their existence and future recovery.
Established reserves are calculated as proven reserves plus 50 percent of risked
probables. Disclosed reserve quantities are gross of royalty volumes.

ASSET IMPAIRMENT

The Company is required to provide for future removal and site restoration
costs, net of expected recoveries. The Company must estimate these costs in
accordance with existing laws, contracts or other policies and must estimate the
expected recoveries, which is generally the salvage value or residual value of
an asset. These estimated net costs are charged to earnings and the appropriate
liability account over the expected service life of the asset. Site restoration
costs incurred in the year reduce the amount of the liability. When the future
removal and site restoration costs cannot be reasonably determined, a contingent
liability may exist. Contingent liabilities are charged to earnings when
management is able to determine the amount and the likelihood of the future
obligation.

CHANGES IN ACCOUNTING POLICY

STOCK-BASED COMPENSATION

During the fourth quarter of 2001, the Company early adopted the new
recommendation of the Canadian Institute of Chartered Accountants ("CICA") with
respect to accounting for stock-based compensation. The Company adopted this
accounting policy retroactively, without restating the consolidated financial
statements of prior periods. Under the fair value method, the Company records a
compensation expense in the financial statements for granted share options.

The Company has a stock-based compensation plan, which includes stock options
and an employee stock savings plan. Consideration received from employees or
directors on the exercise of stock options under the stock option plan is
recorded as capital stock. Compensation costs have not been recognized for fixed
stock options granted to employees and directors. The Company matches employee
contributions to the stock savings plan and these cash payments are recorded as
compensation expense.

FOREIGN CURRENCY TRANSLATION

Effective January 1, 2002 the Company adopted the CICA amended accounting
standard with respect to accounting for foreign currency translation. As a
result of adopting this amended standard, gains or losses on the translation of
long-term debt denominated in U.S. dollars are no longer deferred and amortized
over the term of the debt, but are recognized in earnings.

FUTURE INCOME TAXES

Effective January 1, 2000 the Company adopted the new recommendations of the
CICA with respect to accounting for future income taxes. Under the new
recommendations the liability method of tax allocation is used, which is based
upon the difference between financial and tax bases of assets and liabilities.



36
<PAGE>

2003 OUTLOOK

Compton is projecting an 11 percent increase in 2003 production over 2002.
Average annual production growth in 2003 will be limited due to temporary
facility constraints. Compton expects to drill 142 net wells, incurring capital
expenditures of $171 million. Of this amount, approximately $101 million will be
directed towards drilling and completion activities, allocated 35 percent to
exploration and 65 percent to development projects.

The Company's 2003 capital expenditure program reflects estimated 2003 realized
average commodity prices of $5.45 per mcf of natural gas and $34.85 per barrel
of crude oil. These prices are based upon US$4.35 per mcf (NYMEX) and US$24.85
per barrel (WTI). The Company has a large inventory of drilling prospects and
can quickly increase its capital expenditure program if commodity prices remain
strong. The Company will fund its 2003 capital program with cash flow from
operations.

Cash flow will be dependent upon a number of variables, including forecast
prices and production. The table below outlines critical assumptions:

2003 ESTIMATES

--------------------------------------------------------------------------------
Production
         Natural gas (mmcf/d)                                             130
         Oil and ngls (bbls/d)                                          6,500
         Oil equivalent (boe/d)                                        28,000

     Capital expenditures ($000s)                                   $ 171,000
     Wells drilled (net)                                                  142

Pricing
     Natural gas        (US$/mcf) NYMEX                             $    4.35
                        (Cdn$/mcf) corporate                        $    5.45
     Crude oil          (US$/bbl ) WTI                              $   24.85
                        (Cdn$/bbl) corporate                        $   34.85

Exchange rate           (Cdn$ = US$)                                     0.65
--------------------------------------------------------------------------------

SENSITIVITIES

The Company's 2003 estimated cash flow is sensitive to fluctuations in oil and
natural gas prices as follows:

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------
CASH FLOW (CDN$)                                                 ($000s)          ($/SHARE
                                                                                     BASIC)
--------------------------------------------------------------------------------------------
<S>                                                               <C>         <C>
Change of US$0.10/mcf in the price of natural gas (NYMEX)         5,000       $       0.04
Change of US$1.00/bbl in the price of crude oil (WTI)             2,500       $       0.02
--------------------------------------------------------------------------------------------
</TABLE>



                                                                              37
<PAGE>

BUSINESS CONDITIONS, RISKS AND RISK MITIGATION

BUSINESS CONDITIONS AND RISKS

Compton's operations are subject to risks normally associated with the oil and
natural gas industry. The most important of these are set out below, together
with the strategies Compton employs to mitigate and minimize these risks.

INHERENT INDUSTRY RISK THAT EXPLORATION AND DEVELOPMENT PROGRAMS MAY NOT RESULT
IN ECONOMIC RESERVE ADDITIONS TO REPLACE PRODUCTION. Compton's strategies to
minimize this inherent risk include focusing on selected areas in Western
Canada, utilizing a team of highly qualified professionals with expertise and
experience in these areas, expanding operations in core areas, continuously
assessing strategic acquisitions to complement existing activities and striving
for a balance between exploration and lower-risk development and exploitation
prospects.

FINANCIAL RISKS INCLUDING COMMODITY PRICES AND EXPENDITURE COSTS SHIFTING DUE TO
CHANGES IN MARKET CONDITIONS. Commodity prices are driven by supply, demand and
market forces outside the Company's influence. Compton monitors and focuses its
expenditures to reflect price and production changes. Compton continuously
monitors market conditions and opportunities. From time to time the Company will
employ financial instruments to manage exposure related to Canada/U.S. exchange
rates and commodity prices.

The Company has commodity and fixed-price contracts outstanding as outlined in
the Risk Mitigation section of this MD&A. The Company considers longer-term
contracts with suppliers, where appropriate, to mitigate shifts in costs
resulting from changes in industry and market conditions. Compton has no control
over government intervention or taxation levels on the industry.

It is likely that in the future the Company will be required to raise additional
capital via debt and/or equity financings in order to fully realize its
strategic goals and business plans. Compton's ability to raise additional
capital will depend upon a number of factors, such as general economic and
market conditions that are beyond its control. If Compton is unable to obtain
additional financing or to obtain it on favourable terms, the Company might be
required to forego attractive business opportunities. Compton is committed to
maintaining a strong balance sheet, combined with a flexible capital expenditure
program, that can be adjusted to capitalize on or reflect acquisition
opportunities or a tightening of liquidity sources.

MECHANICAL AND OPERATIONAL RISKS ASSOCIATED WITH THE DRILLING FOR, PRODUCTION
AND PROCESSING OF NATURAL GAS AND CRUDE OIL, INCLUDING DAMAGE TO THE COMPANY'S
EQUIPMENT AND THE LIABILITY ASSOCIATED WITH AN OCCURRENCE OR MALFUNCTION.
Compton manages operational risks by employing skilled professionals utilizing
leading-edge technology and conducting regular maintenance and training
programs. The Company has both an operational emergency response plan and an
operational safety manual. In addition, a comprehensive insurance program is
maintained to mitigate risks and protect against significant losses where
possible.

Compton operates in accordance with all applicable environmental legislation.
The Company strives to maintain or surpass compliance with such regulations and
works with government agencies, landholders and other parties to minimize the
environmental impact of its activities.



38
<PAGE>

Compton is also subject to various government-imposed regulatory risks, some of
which are beyond the Company's control. Compton has established an Engineering,
Environmental, Health and Safety Committee to ensure that employees and the
environment are protected while the Company is engaged in its exploration and
development activities. Policies and procedures have been established to ensure
environmental protection standards are maintained and standards of operating
practice are designed to minimize risk to employees and the environment.

RISK MITIGATION

From time to time, the Company enters into hedge transactions to manage
fluctuations in commodity prices and foreign currency. Hedging contracts are
utilized to support the economics of both corporate and property acquisitions.
Oil and natural gas revenues for 2002 included gains of $1.2 million (2001 -
gain of $3.7 million) on such transactions.

Currently, the Company has hedged approximately 30 percent of its current 2003
production and no hedging contracts are in place for 2004.

Hedging transactions have been entered into as follows:

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------
                                  DAILY VOLUME
----------------------------------------------------------------------------------------------------------------------
    COMMODITY        TYPE                 TERM                                            PRICE              INDEX
----------------------------------------------------------------------------------------------------------------------
   <S>             <C>        <C>                                   <C>             <C>                       <C>
   Natural gas     Collars     November 2002 - March 2003            23.8 mmcf      $4.33/mcf - $7.18/mcf     AECO
   Natural gas     Collars      April 2003 - October 2003            33.3 mmcf      $4.88/mcf - $7.93/mcf     AECO
   Natural gas      Fixed       April 2003 - October 2003             4.8 mmcf                  $6.85/mcf     AECO
    Crude oil       Fixed     January 2003 - December 2003          1,500 bbls               US$27.00/bbl     WTI
    Crude oil      Collar     January 2003 - December 2003            500 bbls             US$23.50/bbl -     WTI
                                                                                             US$27.00/bbl
</TABLE>

<TABLE>
<CAPTION>
FOREIGN                                                            DAILY
CURRENCY             TYPE                 TERM                NOTIONAL AMOUNT         EXCHANGE RATE        INDEX RATE
----------------------------------------------------------------------------------------------------------------------
<S>                 <C>       <C>                                 <C>                 <C>                   <C>
US$                 Fixed     January 2003 - December 2003        US$37,250           Cdn $1.583 / US$1      Bank of
                                                                                                             Canada
                                                                                                              Noon
------------------ --------- -------------------------------- ----------------- -------------------------- -----------
</TABLE>


                                                                              39
<PAGE>

                                                                      DOCUMENT 3
                                                                      ----------



MANAGEMENT'S REPORT

The accompanying consolidated financial statements of Compton Petroleum
Corporation and all other financial and operating information contained in this
Annual Report are the responsibility of management. The consolidated financial
statements have been prepared in accordance with accounting policies detailed in
the notes to the consolidated financial statements and in accordance with
generally accepted accounting principles in Canada.

The Company's systems of internal control have been designed and maintained to
provide reasonable assurance that assets are properly safeguarded and that the
financial records are sufficiently well maintained to provide relevant, timely
and reliable information to management.

External auditors, appointed by the shareholders, have independently examined
the consolidated financial statements. They have performed such tests as they
deemed necessary to enable them to express an opinion on these consolidated
financial statements.

An Audit Committee of the Board of Directors has reviewed these consolidated
financial statements with management and the external auditors. The Board of
Directors has approved the consolidated financial statements on the
recommendation of the Audit Committee.

/s/ E.G. Sapieha                         /s/ N.G. Knecht


E.G. Sapieha, C.A.                       N.G. Knecht, C.A.
President and                            Vice President Finance and
Chief Executive Officer                  Chief Financial Officer



40
<PAGE>

INDEPENDENT AUDITORS' REPORT

To the Shareholders of Compton Petroleum Corporation

We have audited the consolidated balance sheets of Compton Petroleum Corporation
as at December 31, 2002 and 2001 and the consolidated statements of earnings and
retained earnings and cash flow for each of the years in the three year period
ended December 31, 2002. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted
in Canada and the United States of America. These 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 disclosure 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, 2002
and 2001 and the results of its operations and cash flow for each of the years
in the three year period ended December 31, 2002 in accordance with accounting
principles generally accepted in Canada.


Calgary, Alberta                             (Signed) "Grant Thornton LLP"
March 14, 2003                               Chartered Accountants


COMMENTS BY AUDITOR FOR U.S. READERS ON CANADA-U.S. REPORTING DIFFERENCES

In the United States of America, reporting standards for auditors require the
addition of an explanatory paragraph (following the opinion paragraph) when
there is a change in accounting principles that has a material effect on the
comparability of the Company's financial statements, such as the changes
described in Note 3 to the consolidated financial statements. Our report to the
shareholders dated March 14, 2003 is expressed in accordance with Canadian
reporting standards which do not require a reference to such a change in
accounting principles in the Auditors' Report when the change is properly
accounted for and adequately disclosed in the consolidated financial statements.


Calgary, Alberta                             (Signed) "Grant Thornton LLP"
Canada                                       Chartered Accountants
March 14, 2003


                                                                              41
<PAGE>

CONSOLIDATED BALANCE SHEETS


($000S)
--------------------------------------------------------------------------------
DECEMBER 31,                                                  2002          2001
--------------------------------------------------------------------------------

ASSETS

Current
     Cash                                             $     14,725  $      5,052
     Accounts receivable and other                          80,689        82,001
--------------------------------------------------------------------------------

                                                            95,414        87,053
Deferred financing charges                                  13,444             -
Property and equipment (Note 5)                            708,414       606,920
--------------------------------------------------------------------------------
                                                      $    817,272  $    693,973
================================================================================

LIABILITIES

Current
     Bank debt (Note 6)                               $     40,000  $    230,000
     Accounts payable                                       63,275        64,903
--------------------------------------------------------------------------------

                                                           103,275       294,903
Senior term notes (Note 7)                                 260,634             -
Capital lease obligations (Note 8)                             126           449
Future income taxes (Notes 3 and 13)                       205,193       179,192
Future site restoration (Note 9)                             2,245         1,569
--------------------------------------------------------------------------------
                                                           571,473       476,113
================================================================================

SHAREHOLDERS' EQUITY

Capital stock (Note 10)                                    128,079       116,572
Retained earnings                                          117,720       101,288
--------------------------------------------------------------------------------
                                                           245,799       217,860
================================================================================
                                                           817,272  $    693,973
--------------------------------------------------------------------------------


Commitments and contingencies (Note 16)

On behalf of the Board:

     Director                                           Director

See accompanying notes to the consolidated financial statements.



42
<PAGE>

CONSOLIDATED STATEMENTS OF EARNINGS AND RETAINED EARNINGS


($000S, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------
YEARS ENDED DECEMBER 31,                                 2002         2001         2000
-----------------------------------------------------------------------------------------
<S>                                                 <C>          <C>          <C>
REVENUE
     Oil and gas revenues                           $ 219,787    $ 244,970    $ 213,376
     Royalties, net                                    47,497)     (55,919)     (44,695)
-----------------------------------------------------------------------------------------
                                                      172,290      189,051      168,681
=========================================================================================

EXPENSES
     Operating                                         45,546       40,222       31,571
     General and administrative                         9,845        6,582        5,915
     Interest                                          20,130       12,863       12,772
     Depletion and depreciation                        56,003       50,450       41,767
-----------------------------------------------------------------------------------------

                                                      131,524      110,117       92,025
     Unrealized foreign exchange loss (Note 3)          1,583           --           --
     Stock-based compensation (Note 11)                   190         (280)          --
-----------------------------------------------------------------------------------------

                                                      133,297      109,837       92,025
=========================================================================================

EARNINGS BEFORE TAXES                                  38,993       79,214       76,656
-----------------------------------------------------------------------------------------

TAXES
     Future income taxes (Note 13)                     18,767       22,248       35,707
     Capital taxes                                      1,428        1,330          890
-----------------------------------------------------------------------------------------
                                                       20,195       23,578       36,597
=========================================================================================

NET EARNINGS                                           18,798       55,636       40,059

RETAINED EARNINGS, beginning of year                  101,288       63,324       27,197
-----------------------------------------------------------------------------------------
                                                      120,086      118,960       67,256

Change in accounting policies (Note 3)                     --       (3,585)        (380)
Premium on redemption of shares (Note 10)              (2,366)     (14,087)      (3,552)
-----------------------------------------------------------------------------------------

RETAINED EARNINGS, end of year                      $ 117,720    $ 101,288    $  63,324
=========================================================================================

EARNINGS PER SHARE
     Basic                                          $    0.17    $    0.51    $    0.37
     Diluted (Note 12)                              $    0.16    $    0.48    $    0.36
-----------------------------------------------------------------------------------------
</TABLE>

See accompanying notes to the consolidated financial statements.


                                                                              43
<PAGE>

CONSOLIDATED STATEMENTS OF CASH FLOW


<TABLE>
<CAPTION>
($000S, EXCEPT PER SHARE DATA)
-----------------------------------------------------------------------------------------
YEARS ENDED DECEMBER 31,                                 2002         2001         2000
-----------------------------------------------------------------------------------------
<S>                                                 <C>          <C>          <C>
CASH DERIVED FROM (APPLIED TO)

OPERATING
     Net earnings                                   $  18,798    $  55,636    $  40,059
     Items not affecting cash
       Depletion and depreciation                      56,003       50,450       41,767
       Future income taxes                             18,767       22,248       35,707
       Amortization of deferred charges                 1,367           --           --
       Unrealized foreign exchange loss                 1,583           --           --
-----------------------------------------------------------------------------------------

     Cash flow from operations                         96,518      128,334      117,533
     Change in non-cash working capital (Note 15)      (4,843)      (7,266)     (13,346)
-----------------------------------------------------------------------------------------
                                                       91,675      121,068      104,187
=========================================================================================

FINANCING
     Increase (decrease) in bank loan                (190,000)      36,304       23,662
     Capital lease obligations                           (323)         (38)          --
     Issue of senior notes                            259,050           --           --
     Deferred financing charges                       (14,810)          --           --
     Proceeds from share issues, net                   18,177       41,558       11,844
     Redemption of common shares                       (3,026)     (17,774)      (5,564)
     Change in non-cash working capital (Note 15)       3,514           --           --
-----------------------------------------------------------------------------------------
                                                       72,582       60,050       29,942
-----------------------------------------------------------------------------------------
Cash available for investing activities               164,257      181,118      134,129
-----------------------------------------------------------------------------------------

INVESTING
     Property and equipment additions                (127,993)    (147,993)    (118,153)
     Corporate acquisitions (Note 4)                       --      (29,669)          --
     Property acquisitions                            (44,857)     (18,974)     (33,513)
     Property dispositions                             17,700        8,731       33,272
     Site restoration                                    (446)        (473)        (368)
     Change in non-cash working capital (Note 15)       1,012       12,312         (307)
-----------------------------------------------------------------------------------------
                                                     (154,584)    (176,066)    (119,069)
-----------------------------------------------------------------------------------------

CHANGE IN CASH                                          9,673        5,052       15,060

CASH, BEGINNING OF YEAR                                 5,052           --      (15,060)
-----------------------------------------------------------------------------------------

CASH, END OF YEAR                                      14,725    $   5,052    $      --
=========================================================================================

CASH FLOW FROM OPERATIONS PER SHARE
     Basic                                          $    0.85    $    1.17    $    1.10
     Diluted (Note 12)                              $    0.82    $    1.12    $    1.06
-----------------------------------------------------------------------------------------
</TABLE>

See accompanying notes to the consolidated financial statements.


44
<PAGE>

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(TABULAR AMOUNTS IN $000S, UNLESS OTHERWISE STATED)
DECEMBER 31, 2002

1.   NATURE OF OPERATIONS

     The Company is engaged primarily in the exploration for and production of
     petroleum and natural gas reserves in a single cost centre, being the
     Western Canada Sedimentary Basin.

2.   SIGNIFICANT ACCOUNTING POLICIES

     A)  BASIS OF PRESENTATION

         The consolidated financial statements of the Company have been prepared
         in accordance with Canadian generally accepted accounting principles
         within the framework of the accounting policies summarized below.

         The consolidated financial statements include the accounts of the
         Company and its wholly-owned subsidiaries from the respective dates of
         acquisition. Inter-company transactions and balances are eliminated
         upon consolidation.

     B)  PETROLEUM AND NATURAL GAS PROPERTIES

         i)   CAPITALIZED COSTS

              The Company follows the full cost method of accounting for its
              petroleum and natural gas operations. Under this method all costs
              related to the exploration for and development of petroleum and
              natural gas reserves are capitalized. Costs include lease
              acquisition costs, geological and geophysical expenses, interest
              on debt directly related to certain acquisitions, and costs of
              drilling both productive and non-productive wells. Proceeds from
              the sale of properties are applied against capitalized costs,
              without any gain or loss being realized, unless such sale would
              significantly alter the rate of depletion and depreciation.

         ii)  DEPLETION AND DEPRECIATION

              Depletion of exploration and development costs and depreciation of
              production equipment is provided using the unit-of-production
              method based upon estimated proven petroleum and natural gas
              reserves. The costs of significant undeveloped properties are
              excluded from costs subject to depletion. For depletion and
              depreciation purposes, relative volumes of petroleum and natural
              gas production and reserves are converted at the energy equivalent
              conversion rate of six thousand cubic feet of natural gas to one
              barrel of crude oil.

              Depreciation of office equipment is provided for on a
              declining-balance basis at 20 percent per annum.


                                                                              45
<PAGE>

2.   SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

         iii) CEILING TEST

              In applying the full cost method, the Company calculates a ceiling
              test whereby the carrying value of petroleum and natural gas
              properties and production equipment, net of recorded future income
              taxes and the accumulated provision for site restoration and
              abandonment costs, is compared annually to an estimate of future
              net cash flow from the production of proven reserves. Net cash
              flow is estimated using year end prices, less estimated future
              general and administrative expenses, financing costs and income
              taxes. Should this comparison indicate an excess carrying value,
              the excess is charged against earnings as additional depletion and
              depreciation.

         iv)  FUTURE SITE RESTORATION AND ABANDONMENT COSTS

              Estimated costs of future site restoration and abandonments, net
              of recoveries, are provided for over the life of proven reserves
              on a unit-of-production basis. An annual provision is recorded as
              additional depletion and depreciation. Costs are based on
              engineering estimates of the anticipated method and extent of site
              restoration in accordance with current legislation, industry
              practices and costs. The accumulated provision is reflected as a
              non-current liability and actual expenditures are charged against
              the accumulated provision when incurred.

      C) FINANCIAL INSTRUMENTS

         Financial instruments consist mainly of accounts receivable and other,
         accounts payable and long-term debt. There are no significant
         differences between the carrying value of these financial instruments
         and their estimated fair value.

         The Company uses financial instruments for non-trading purposes to
         manage fluctuations in commodity prices, foreign currency exchange
         rates and interest rates, as described in Note 14. Hedge accounting is
         used when there is a high degree of correlation between price movements
         in the financial instrument and the item designated as being hedged.
         Gains and losses are recognized in the same period as the hedged item.
         If correlation ceases, hedge accounting is terminated and future
         changes in the market value of the financial instrument are recognized
         as gains or losses in the period. To date, the correlation has remained
         strong and all gains and losses from these financial instruments have
         been recorded using hedge accounting.

     D)  JOINT OPERATIONS

         Certain petroleum and natural gas activities are conducted jointly with
         others. These consolidated financial statements reflect only the
         Company's proportionate interest in such activities.

     E)  FLOW-THROUGH SHARES

         Resource expenditure deductions for income tax purposes related to
         exploration and development activities funded by flow-through share
         arrangements are renounced to investors in accordance with income tax
         legislation. Future income tax liability is increased and capital stock
         is reduced by the estimated tax benefits transferred to shareholders.


46
<PAGE>

     F)  PER SHARE AMOUNTS

         The treasury stock method is used to determine the dilutive effect of
         stock options. The treasury stock method assumes that proceeds received
         from the exercise of in-the-money stock options are used to repurchase
         common shares at the average market rate.

     G)  USE OF ESTIMATES

         The preparation of consolidated financial statements in accordance with
         accounting principles generally accepted in Canada requires management
         to make assumptions and estimates that affect the reported amounts of
         assets and liabilities at the date of the consolidated financial
         statements and the reported amounts of revenues and expenses during the
         reporting period. Actual results may differ from estimated amounts as
         future confirming events occur.

     H)  INCOME TAXES

         Income taxes are recorded using the liability method of tax allocation.
         Future income taxes are calculated based on temporary differences
         arising from the difference between the tax basis of an asset or
         liability and its carrying value using tax rates anticipated to apply
         in the periods when the temporary differences are expected to reverse.

     I)  REVENUE RECOGNITION

         Revenue associated with the production and sales of crude oil, natural
         gas and natural gas liquids owned by the Company are recognized when
         title passes from the Company to its customer.

     J)  STOCK-BASED COMPENSATION PLAN

         The Company has a stock-based compensation plan, which includes stock
         options and an employee stock savings plan.

         Consideration received from employees or directors on the exercise of
         stock options under the stock option plan is recorded as capital stock.
         Compensation costs have not been recognized for fixed stock options
         granted to employees and directors. The Company matches employee
         contributions to the stock savings plan and these cash payments are
         recorded as compensation expense.

     K)  DEFERRED FINANCING CHARGES

         Financing costs related to the issuance of the senior term notes have
         been deferred and are amortized over the term of the respective senior
         term notes on a straight-line basis.

     L)  FOREIGN CURRENCY TRANSLATION

         Long-term debt payable in U.S. dollars is translated into Canadian
         dollars at the period-end exchange rate, with any resulting adjustment
         recorded in the consolidated statements of earnings and retained
         earnings.

     M)  DIVIDEND POLICY

         The Company has neither declared nor paid any dividends on its common
         shares. The Company intends to retain its earnings to finance growth
         and expand its operations and does not anticipate paying any dividends
         on its common shares in the foreseeable future.

                                                                              47
<PAGE>

3.   CHANGES IN ACCOUNTING POLICIES

     A)  Effective January 1, 2002, the Company adopted the Canadian Institute
         of Chartered Accountants ("CICA") amended accounting standard with
         respect to accounting for foreign currency translation. As a result of
         adopting this amended standard, gains or losses on the translation of
         long-term debt denominated in U.S. dollars are no longer deferred and
         amortized over the term of the debt, but are recognized in earnings.
         The adoption of this amended standard resulted in an unrealized foreign
         exchange loss of $1.6 million for the fiscal year ended December 31,
         2002. This amended standard affects the Company's accounting for its
         U.S. denominated senior term notes due May 15, 2009 (refer to Note 7).

     B)  During the fourth quarter of 2001, the Company early adopted the new
         recommendations of the CICA with respect to accounting for stock-based
         compensation. The Company has adopted this accounting policy
         retroactively, without restating the consolidated financial statements
         of prior periods. Effective January 1, 2001, the Company recorded a
         reduction in retained earnings of $3.6 million, an increase in accounts
         payable of $6.2 million and a decrease in future income tax liability
         of $2.6 million.

     C)  Effective January 1, 2000, the Company adopted the new recommendations
         of the CICA with respect to accounting for future income taxes. Under
         the new recommendations the liability method of tax allocation is used,
         which is based upon the difference between financial and tax bases of
         assets and liabilities.

         The Company has adopted this change in accounting policy retroactively,
         without restating the consolidated financial statements of prior
         periods. As a result, the Company recorded a reduction in retained
         earnings of $0.4 million, an increase in property and equipment of
         $68.1 million and an increase in the future income tax liability of
         $68.5 million, as at January 1, 2000.

     D)  The CICA approved a new standard for the compilation and disclosure of
         per share amounts. In 2000, the Company retroactively adopted the new
         standard. Under this standard, the treasury stock method is used
         instead of the imputed earnings method to determine the dilutive effect
         of stock options and other dilutive instruments.

         Prior period diluted earnings per share and cash flow from operations
         per share have been restated for this change in accounting policy. If
         the imputed method had been used to calculate these amounts, the
         reported amounts would have been for the year ended December 31, 2000,
         diluted earnings per share - $0.35 and diluted cash flow from
         operations per share - $1.03.


48
<PAGE>

4.   ACQUISITION

     Effective July 16, 2001, the Company acquired all of the issued and
     outstanding shares of Hornet Energy Ltd. ("Hornet"), a public company
     involved in the exploration, development and production of oil and natural
     gas primarily in southern Alberta. The acquisition has been accounted for
     by the purchase method of accounting and the consolidated financial
     statements include the results of operations from date of acquisition. The
     fair value of the assets acquired is as follows:

     ---------------------------------------------------------------------------

     Net assets acquired
          Petroleum and natural gas properties               $    54,276
          Future income taxes                                    (12,236)
     ---------------------------------------------------------------------------
                                                                  42,040
          Working capital deficiency                              (1,460)
          Long-term debt                                         (10,320)
          Capital lease obligations                                 (591)
     ---------------------------------------------------------------------------
                                                             $    29,669
     ---------------------------------------------------------------------------

     Consideration
          Cash                                               $    29,134
          Transaction costs                                          535
     ---------------------------------------------------------------------------
                                                             $    29,669
     ---------------------------------------------------------------------------

     The following table reflects unaudited pro forma combined results of
     operations of the Company and the above acquisition on the basis that the
     acquisition had taken place at the beginning of the fiscal years presented:

     ---------------------------------------------------------------------------
                                                         2001            2000
     ---------------------------------------------------------------------------
     Revenue, net of royalties                      $ 195,593       $ 176,777
     Net earnings                                      52,111          39,958
     Earnings per share
     Basic                                          $    0.47       $    0.37
     Diluted                                        $    0.45       $    0.36
     ---------------------------------------------------------------------------



                                                                              49
<PAGE>

5.   PROPERTY AND EQUIPMENT

     ---------------------------------------------------------------------------
                                                           2002         2001
     ---------------------------------------------------------------------------

     Exploration and development costs                $ 758,716    $ 635,508
     Accumulated depletion                             (158,581)    (109,091)
     ---------------------------------------------------------------------------

                                                        600,135      526,417
     ---------------------------------------------------------------------------

     Production equipment and processing facilities     120,537       88,727
     Office equipment                                     4,215        2,808
     ---------------------------------------------------------------------------

                                                        124,752       91,535
     Accumulated depreciation                           (16,473)     (11,032)
     ---------------------------------------------------------------------------

                                                        108,279       80,503
     ---------------------------------------------------------------------------

                                                      $ 708,414    $ 606,920
     ---------------------------------------------------------------------------

     The Company does not capitalize any portion of its general and
     administrative expenses. During the year ended December 31, 2002 - nil
     (2001 - nil; 2000 - $0.7 million) of interest expense associated with
     certain property acquisitions and processing facilities was capitalized.

     Future capital expenditures of $37.5 million (2001- $33.0 million; 2000 -
     $37.1 million), as estimated by independent engineers, relating to the
     development of proven non-producing reserves have been included in costs
     subject to depletion, and undeveloped properties with a cost at December
     31, 2002 of $155.0 million (2001- $161.0 million; 2000 - $98.8 million),
     included in exploration and development costs, have not been subject to
     depletion.

6.   CREDIT FACILITIES

     ---------------------------------------------------------------------------
                                                           2002         2001
     ---------------------------------------------------------------------------

     Bank credit facilities                         $    40,000  $   230,000
     ---------------------------------------------------------------------------

     As at December 31, 2002, the Company had authorized syndicated senior
     credit facilities with Canadian financial institutions, in the amount of
     $168 million (2001 - $240 million). The senior credit facilities consist of
     a $158 million (2001 - $230 million) extendible revolving credit facility
     and a $10 million (2001- $10 million) working capital facility. As a result
     of the Company's US$165 million senior notes issuance, the Company's senior
     credit facilities were adjusted to $168 million. Advances under the
     facilities can be drawn in either Canadian or U.S. funds. The facilities
     bear interest at the lenders' prime lending rate or at the Bankers'
     Acceptance rate or LIBOR plus a margin based on the ratio of total
     consolidated debt to cash flow, currently set at 0.625 percent, 1.625
     percent and 1.625 percent, respectively. These facilities mature on July 9,
     2003.


50
<PAGE>

     Effective July 1, 2002, the Company has adopted the recommendations of the
     CICA's Emerging Issues Committee Abstract 122 concerning the presentation
     of revolving demand loans. As such, the Company has classified borrowing
     under its bank credit facilities as a current liability. The bank loan at
     December 31, 2001 has been restated to conform with current presentation.

     The credit facilities are secured by a first fixed and floating charge
     debenture in the amount of $325 million covering all the Company's assets
     and undertakings.

7.   SENIOR TERM NOTES
<TABLE>
<CAPTION>
     ---------------------------------------------------------------------------------------
                                                                      2002             2001
     ---------------------------------------------------------------------------------------
     <S>                                                       <C>                   <C>
     Senior term notes (US$165,000,000)
          Proceeds on issuance                                 $   259,051           $   --
          Increase due to unrealized foreiqn exchange loss           1,583               --
     ---------------------------------------------------------------------------------------

                                                               $   260,634           $   --
     ---------------------------------------------------------------------------------------
</TABLE>

     On May 8, 2002, the Company completed an offering of US$165 million senior
     notes bearing interest at 9.9 percent with principal repayable on May 15,
     2009. Interest is payable on May 15 and November 15 of each year, beginning
     on November 15, 2002. The Company used the net proceeds to repay its entire
     existing bank indebtedness and for general corporate purposes. These senior
     notes are unsecured and are subordinate to the Company's bank credit
     facilities.

     Concurrent with the closing of the senior notes offering, the Company
     entered into interest rate swap arrangements with its banking syndicate
     whereby interest paid by the Company on the US $165 million principal
     amount will be based upon the 90-day Bankers' Acceptance rate plus 4.85
     percent. This arrangement resulted in an effective interest rate of 7.65
     percent during the year ended December 31, 2002.

8.   CAPITAL LEASES

     Certain leases relating to gas processing equipment, having costs in the
     aggregate of $601 thousand and accumulated depreciation of $93 thousand
     (2001 - $36 thousand), are classified as capital leases and are included in
     property and equipment. These capital lease obligations were acquired as
     part of the Hornet acquisition referred to in Note 4. Each lease contains
     an option to purchase and has an implicit interest rate of 7.8 percent to
     8.8 percent. Excluded from the following future capital lease payment
     obligations is interest in the amount of $49 thousand.

     ---------------------------------------------------------------------------
     2003                                                            $     323
     2004                                                                   36
     2005                                                                   38
     2006                                                                   52
     ---------------------------------------------------------------------------
                                                                           449
     Less:  current portion, included in accounts payable                  323
     ---------------------------------------------------------------------------

                                                                     $     126
     ---------------------------------------------------------------------------


                                                                              51
<PAGE>

9.   SITE RESTORATION AND ABANDONMENTS

     At December 31, 2002 total future removal and site restoration costs to be
     accrued over the life of the remaining proven reserves were estimated, net
     of recoveries, at $18.8 million (2001- $8.5 million) of which $2.2 million
     (2001- $1.6 million) has been accrued. This estimate is subject to change
     based on amendments to environmental laws and as new information concerning
     operations becomes available.

10.  CAPITAL STOCK

     A)  AUTHORIZED

         Unlimited number of common shares
         Unlimited number of preferred shares, issuable in series

     B)  ISSUED AND OUTSTANDING
<TABLE>
<CAPTION>
     --------------------------------------------------------------------------------------------------------------
                                                             2002                                2001
     --------------------------------------------------------------------------------------------------------------
                                                   NUMBER            AMOUNT            NUMBER            AMOUNT
                                                 OF SHARES                           OF SHARES
     --------------------------------------------------------------------------------------------------------------
     <S>                                       <C>                 <C>             <C>                 <C>
     Common shares
          Balance, beginning of year           113,105,450         $ 116,572       108,783,649         $  94,472
              Issued for cash, net               3,085,175             9,711         7,345,604            22,964
              Issued for property                  350,000             1,225           241,997             1,285
              Issued for cash on
                   exercise of warrants                 --                --           625,616             1,095
              Issued for cash on
                   exercise of options             526,506             1,397           314,584               443
              Repurchased for cash                (796,000)             (826)       (4,206,000)           (3,687)
     --------------------------------------------------------------------------------------------------------------

          Balance, end of year                 116,270,931         $ 128,079      113,105,450          $ 116,572
     --------------------------------------------------------------------------------------------------------------
</TABLE>

         During 2002, common shares issued for cash include 3,085,175 (2001-
         7,345,604) common shares issued on a flow-through basis. Under the
         terms of the current year flow-through agreements, the Company is
         required to expend $17.6 million on qualifying oil and natural gas
         expenditures prior to December 31, 2003. As at December 31, 2002, the
         Company had not incurred any qualifying expenditures.

         During the year, the Company repurchased for cancellation 796,200
         common shares at an average price of $3.80 per share (2001- 4,206,000
         shares at an average price of $4.23 per share), pursuant to a normal
         course issuer bid. The excess of the purchase price over book value has
         been charged to retained earnings.


52
<PAGE>

    C)   OUTSTANDING WARRANTS

         In 1998, in conjunction with the disposition of certain facilities, the
         Company issued share purchase warrants to a third party, which entitled
         the holder to acquire 3,000,000 common shares of the Company. As at
         December 31, 2002, nil (2001 - nil; 2000 - 1,000,000) warrants were
         outstanding at an exercise price of $1.75 per share. The warrants were
         exercisable on the basis of 10,000 warrants for each $250,000 paid to
         the Company as an incentive fee under the terms of the disposition.
         During 2001, a total of 625,616 warrants were exercised for gross
         proceeds of $1.1 million. The remaining warrants were cancelled.

     D)  SHAREHOLDER RIGHTS PLAN

         The Company has a Shareholder Rights Plan to ensure all shareholders
         are treated fairly in the event of a takeover offer or other
         acquisition of control of the Company.

         Pursuant to the Plan, the Board of Directors authorized and declared
         the distribution of one Right in respect of each common share
         outstanding. In the event that an acquisition of 20 percent or more of
         the Company's shares is completed and the acquisition is not a
         permitted bid, as defined by the Plan, each Right will permit the
         holder to acquire, at the exercise price of $50.00, such number of
         common shares as have a market value equal to twice the exercise price.

11.  STOCK-BASED COMPENSATION PLANS

     The Company has implemented a Stock Option Plan for directors, officers and
     employees. As of December 31, 2002, there were 14,500,000 common shares
     reserved for issuance to eligible participants. At December 31, 2002,
     10,356,528 (December 31, 2001 - 9,829,334; December 31, 2000 - 6,352,335)
     options with exercise prices between $0.60 and $4.85 were outstanding and
     exercisable at various dates to November 12, 2012. The exercise price of
     each option equals the market price of the Company's common shares on the
     date of the grant.

     SHARE APPRECIATION RIGHTS PLAN

     At the beginning of 2001, the Company had a share appreciation rights plan
     of which, the financial statement effects of this plan were determined not
     to be significant to the consolidated financial statements due to the
     amount vested. During 2001, this plan was cancelled and replaced by a fixed
     option plan with a variable component.

     As a result, a certain number of outstanding fixed options included in the
     Company's Stock Option Plan have a variable compensation cost to them. As
     at December 31, 2001, approximately 2.4 million of the outstanding fixed
     options total of 9.8 million were granted as a result of the aforementioned
     cancelled share appreciation rights plan. These fixed options, with a
     variable component, were granted in two tranches:1.7 million at a fixed
     option exercise price of $3.02 per option share and 0.7 million at a fixed
     option exercise price of $4.00 per option share. Attached to these fixed
     options is a variable compensation component that enables the holder of
     such fixed option to receive a cash payment from the Company upon exercise
     of the fixed option. This cash payment varies with each fixed option
     holder, and is based on the difference between


                                                                              53
<PAGE>

11.  STOCK-BASED COMPENSATION PLANS (CONTINUED)

     the lesser of the market price of the Company's common shares on the date
     the fixed option is exercised or the fixed option exercise price, and a
     stated compensation price for each respective option holder. Under this
     structure, the maximum variable compensation cash payment is the respective
     fixed option exercise price.

     The aggregate variable cost component relating to these fixed options can
     vary in amount between a range based on the market value price of the
     Company's common shares and is limited to a total amount of $3.3 million.
     The liability related to the variable component of these options amounts to
     $3.2 million, and is included in accounts payable as at December 31, 2002
     (2001 - $3.9 million).

     During the year ended December 31, 2002, the Company recorded a
     compensation expense of $190 thousand related to the outstanding variable
     component of these options (2001 - $280 thousand recovery).

     STOCK OPTIONS

     The following tables summarize the information about the stock options as
     at:

<TABLE>
<CAPTION>
     --------------------------------------------------------------------------------------------------------------
                                                                 2002                              2001
     --------------------------------------------------------------------------------------------------------------
                                                                        WEIGHTED                        WEIGHTED
                                                                         AVERAGE                         AVERAGE
                                                                        EXERCISE                         EXERCISE
     FIXED OPTIONS                                    SHARES               PRICE          SHARES            PRICE
     --------------------------------------------------------------------------------------------------------------
     <S>                                             <C>               <C>               <C>             <C>
     Outstanding at beginning of year                9,829,334         $    2.03         6,352,335       $   1.08
     Granted                                         1,669,570         $    4.00         3,866,250       $   3.57
     Exercised                                       (526,506)         $    2.65         (314,584)       $   1.41
     Cancelled                                       (615,870)         $    3.83          (74,667)       $   3.63
     --------------------------------------------------------------------------------------------------------------

     Outstanding at end of year                     10,356,528         $    2.21         9,829,334       $   2.03
     --------------------------------------------------------------------------------------------------------------

     Options exercisable at year-end                7,691, 288         $    1.63         7,009,889       $   1.42
     --------------------------------------------------------------------------------------------------------------
</TABLE>



54
<PAGE>

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------
                                                  OPTIONS OUTSTANDING                       OPTIONS EXERCISABLE
----------------------------------------------------------------------------------------------------------------------
                                             NUMBER         WEIGHTED                           NUMBER
                                        OUTSTANDING          AVERAGE         WEIGHTED     EXERCISABLE        WEIGHTED
                                                 AT        REMAINING          AVERAGE              AT         AVERAGE
                                       DECEMBER 31,      CONTRACTUAL         EXERCISE    DECEMBER 31,        EXERCISE
  RANGE OF EXERCISE PRICES                     2002             LIFE            PRICE            2002           PRICE
----------------------------------------------------------------------------------------------------------------------
<S>                                       <C>                   <C>        <C>              <C>             <C>
$0.60 - $1.25                             4,350,000             3.93       $     0.76       4,350,000       $     0.76
$1.45 - $2.30                             1,526,667             6.71       $     1.90       1,460,000       $     1.88
$2.98 - $3.50                             1,460,199             6.91       $     3.03       1,135,530       $     3.02
$3.80 - $4.85                             3,019,662             8.83       $     4.05         745,758       $     4.04
----------------------------------------------------------------------------------------------------------------------
                                         10,356,528                        $     2.21       7,691,288       $     1.63
----------------------------------------------------------------------------------------------------------------------


----------------------------------------------------------------------------------------------------------------------
                                                  OPTIONS OUTSTANDING                       OPTIONS EXERCISABLE
----------------------------------------------------------------------------------------------------------------------
                                             NUMBER         WEIGHTED                           NUMBER
                                        OUTSTANDING          AVERAGE         WEIGHTED     EXERCISABLE        WEIGHTED
                                                 AT        REMAINING          AVERAGE              AT         AVERAGE
                                       DECEMBER 31,      CONTRACTUAL         EXERCISE    DECEMBER 31,        EXERCISE
  RANGE OF EXERCISE PRICES                     2002             LIFE            PRICE            2002           PRICE
----------------------------------------------------------------------------------------------------------------------

$0.60 - $1.25                             4,380,000             5.17       $     0.77       4,380,000       $     0.77
$1.45 - $2.30                             1,653,334             7.67       $     1.87       1,436,667       $     1.83
$2.98 - $3.50                             1,922,900             9.75       $     3.04         826,899       $     3.02
$3.80 - $4.85                             1,873,100             9.67       $     4.10         366,323       $     3.94
----------------------------------------------------------------------------------------------------------------------
                                          9,829,334                        $     2.03       7,009,889       $     1.42
----------------------------------------------------------------------------------------------------------------------
</TABLE>

     CICA Handbook Section 3870, "Stock-based Compensation", establishes
     financial accounting and reporting standards for stock-based employee
     compensation plans as well as transactions in which an entity issues its
     equity instruments to acquire goods or services from non-employees. The
     Company has elected to follow the intrinsic value method of accounting for
     stock-based compensation arrangements. Since all options were granted with
     an exercise price equal to the market price at the date of the grant, no
     compensation cost has been charged to income at the time of the option
     grants. Had compensation cost for the Company's stock options been
     determined based on the fair market value at the grant dates of the awards
     consistent with methodology prescribed by Handbook Section 3870, the
     Company's net earnings and net earnings per share would have been the
     pro-forma amounts for the periods as indicated on page 56:



                                                                              55
<PAGE>

11. STOCK-BASED COMPENSATION PLANS (CONTINUED)

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------
                                                          2002              2001             2000
---------------------------------------------------------------------------------------------------
<S>                                                  <C>               <C>               <C>
Net earnings
     As reported                                     $  18,798         $  55,636         $  40,059
     Less fair value of stock options                   (2,221)           (2,190)             (652)
---------------------------------------------------------------------------------------------------

     Pro-forma                                       $  16,577         $  53,446         $  39,407

Net earnings per common share - basic
     As reported                                     $    0.17         $    0.51         $    0.37
     Pro-forma                                       $    0.15         $    0.49         $    0.37

Net earnings per common share - diluted
     As reported                                     $    0.16         $    0.48         $    0.36
     Pro-forma                                       $    0.14         $    0.47         $    0.36
---------------------------------------------------------------------------------------------------
</TABLE>

         The weighted average fair market value of options granted for the years
         ended December 31, 2002, 2001 and 2000 are $3.00, $2.52 and $1.61 per
         option, respectively. The fair value of each option granted was
         estimated on the date of grant using the Modified Black-Scholes
         option-pricing model with the following assumptions:

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------
                                                          2002              2001             2000
---------------------------------------------------------------------------------------------------
<S>                                                     <C>               <C>              <C>
Risk-free interest rate                                   5.2%              5.4%             5.5%
Estimated hold period prior to
     exercise (years)                                       10                10               10
Volatility in the price of the Company's
     common shares                                      62.47%            53.75%           52.75%
---------------------------------------------------------------------------------------------------
</TABLE>

12.  PER SHARE AMOUNTS

     Basic earnings per common share and cash flow from operations per common
     share are computed by dividing earnings and cash flow from operations by
     the weighted average number of common shares outstanding for the year.
     Diluted earnings per common share and cash flow from operations per common
     share are computed by dividing earnings and cash flow from operations by
     the diluted weighted average number of common shares outstanding for the
     year. In the calculation of diluted per share amounts, options under the
     stock option plan are assumed to have been converted or exercised on the
     later of the beginning of the year and the date granted. Diluted per share
     amounts reflect the potential dilution that could occur if securities or
     other contracts to issue common shares were exercised or converted to
     common shares.

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------
WEIGHTED AVERAGE SHARES OUTSTANDING (THOUSANDS)           2002              2001             2000
---------------------------------------------------------------------------------------------------
<S>                                                    <C>               <C>              <C>
Basic                                                  113,428           109,881          106,904
Shares issued pursuant to
     stock options and warrants                          4,572             4,963            3,741

Diluted                                                118,000           114,844          110,645
---------------------------------------------------------------------------------------------------
</TABLE>


56
<PAGE>

     In calculating diluted earnings per common share for the year ended
     December 31, 2002, the Company excluded 2,193,662 options (2001 - 892,500),
     because the exercise price was greater than the average market price of its
     common shares in those years.

13.  INCOME TAXES

     A)  PROVISION FOR INCOME TAXES

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------
                                                          2002              2001             2000
---------------------------------------------------------------------------------------------------
<S>                                                 <C>               <C>               <C>
Earnings before taxes                               $   38,993        $   79,214        $   76,656
---------------------------------------------------------------------------------------------------
                                                         42.1%             42.6%            44.6%
Expected tax expense at combined federal
     and provincial rate of
                                                    $   16,424        $   33,745        $   34,204
Increase (decrease) resulting from:
Non-deductible Crown charges                            17,039            18,570           16,915
Alberta royalty tax credits                                 64             (213)            (291)
Resource allowance                                     (14,471)          (22,984)         (17,486)
Statutory rate change                                   (1,340)           (7,400)                -
Other                                                    1,051               530            2,365
---------------------------------------------------------------------------------------------------
                                                    $   18,767        $   22,248        $   35,707
Provision for future income taxes
---------------------------------------------------------------------------------------------------
</TABLE>

B)   FUTURE INCOME TAXES

     Future income taxes consist of the following temporary differences:

--------------------------------------------------------------------------------
                                                          2002             2001
--------------------------------------------------------------------------------
Property and equipment                              $  179,739       $  157,792
Timing of partnership items                             34,494           31,088
Alberta royalty tax deduction                           (5,175)          (5,315)
Non-capital losses                                      (1,360)          (2,162)
Share issue costs and deferred charges                  (1,796)          (1,542)
Future site restoration                                   (709)            (669)
--------------------------------------------------------------------------------
Future income taxes                                 $  205,193       $  179,192
--------------------------------------------------------------------------------



                                                                              57
<PAGE>

14.  FINANCIAL INSTRUMENTS

     The Company is exposed to fluctuations in commodity prices, interest rates
     and Canada/U.S. exchange rates. The Company, when appropriate, utilizes
     financial instruments to manage its exposure to these risks.

     A)  COMMODITY PRICE RISK MANAGEMENT

         The Company enters into hedge transactions on crude oil and natural
         gas. The agreements entered into are forward transactions providing the
         Company with a range of fixed prices on the commodities sold. Oil and
         gas revenues for the year ended December 31, 2002 include gains of $1.2
         million (2001 - $3.7 million gain; 2000 - $7.7 million loss) on these
         transactions.

         The following table outlines the financial agreements in place at
         December 31, 2002:

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------
                                                                                                        UNRECOGNIZED
                                                    DAILY NOTIONAL                                       (GAIN)/LOSS
                              TERM                      VOLUME        PRICES RECEIVED                         ($000s)
----------------------------------------------------------------------------------------------------------------------
<S>                           <C>                   <C>               <C>                                     <C>
Natural gas
     Collar                   Nov 02 - Mar 03       23,810 mcf        $4.33/mcf - $7.18/mcf                     340
     Collar                   Apr 03 - Oct 03       23,810 mcf        $4.88/mcf - $6.20/mcf                   2,487

Crude oil
     Fixed price contract     Jan 03 - Dec 03       1,000 bbls        US$25.50/bbl                              509
     Collar                   Jan 03 - Dec 03       500 bbls          US$23.50/bbl - US$27.00/bbl               247
----------------------------------------------------------------------------------------------------------------------
</TABLE>

         The following table outlines the financial agreements that were entered
         into by the Company, subsequent to December 31, 2002, and are currently
         outstanding:

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------
                                                                                                        UNRECOGNIZED
                                                    DAILY NOTIONAL                                       (GAIN)/LOSS
                              TERM                      VOLUME        PRICES RECEIVED                         ($000s)
----------------------------------------------------------------------------------------------------------------------
<S>                           <C>                   <C>               <C>                                     <C>
Natural gas
     Collar                   Apr 03 - Oct 03       9,524 mcf         $5.78/mcf - $7.93/mcf                       -
     Fixed price contract     Apr 03 - Oct 03       4,762 mcf         $6.85/mcf                                   -

Crude oil
     Fixed price contract     Feb 03 - Dec 03       500 bbls          US$29.60/bbl                                -
----------------------------------------------------------------------------------------------------------------------
</TABLE>



58
<PAGE>

     B)  FOREIGN CURRENCY RISK MANAGEMENT

         The Company is exposed to fluctuations in the exchange rate between the
         Canadian dollar and the U.S. dollar. Crude oil and to a large extent
         natural gas prices are based upon reference prices denominated in U.S.
         dollars, while the majority of the Company's expenses are denominated
         in Canadian dollars. When appropriate, the Company enters into
         agreements to fix the exchange rate of Canadian dollars to U.S. dollars
         in order to manage the risk. During the year a gain of $352 thousand
         was realized and included in revenue (2001 - $nil; 2000 - $353 thousand
         loss). At December 31, 2002 swaps were in place for the period January
         1, 2003 to December 31, 2003. The notional amount swapped thereunder is
         US$37,250 per day at an average exchange rate of Cdn$1.583 resulting in
         an unrealized foreign exchange gain of $43.8 thousand.

     C)  INTEREST RATE RISK MANAGEMENT

         The Company's long-term debt has a fixed interest rate and the Company
         uses interest rate swaps to manage its debt servicing costs. The
         Company currently has an outstanding interest rate swap on a total of
         US$165 million of long-term debt. The terms of the swap convert fixed
         rate interest to floating rate interest which correlates directly to
         long-term debt, 9.9 percent, semi-annual interest obligations (refer to
         Note 7). The effect on the Company was a reduction in the effective
         interest rate to 7.65 percent and an unrealized gain of $15.4 million.

     D)  CREDIT RISK MANAGEMENT

         Accounts receivable include amounts receivable for oil and gas sales
         which are generally made to large creditworthy purchasers, and amounts
         receivable from joint venture partners which are recoverable from
         production. Accordingly, the Company views credit risks on these
         amounts as low.

         The Company is exposed to losses in the event of non-performance by
         counter-parties to these financial instruments. The Company deals with
         major institutions and believes these risks are minimal.

     E)  FAIR VALUE OF FINANCIAL ASSETS AND LIABILITIES

         The fair values of the Company's financial assets and liabilities that
         are included in the Company's consolidated balance sheet as at December
         31, 2002 approximate their carrying value. The fair value of the senior
         term notes does not significantly differ from the carrying amount since
         the estimated interest rates that would be available to the Company at
         December 31, 2002 approximate the actual interest rate of the senior
         term notes.



                                                                              59
<PAGE>

15.  CASH FLOW

     Changes in non-cash working capital items increased (decreased) cash and
     cash equivalents as follows:

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------
                                                          2002              2001              2000
---------------------------------------------------------------------------------------------------
<S>                                                 <C>               <C>               <C>
Accounts receivable and other                       $    1,312        $     (413)       $  (29,568)
Accounts payable                                        (1,629)            5,459            15,915
---------------------------------------------------------------------------------------------------

                                                    $     (317)       $    5,046        $  (13,653)
---------------------------------------------------------------------------------------------------

Operating activities
     Accounts receivable                            $   (6,480)       $  (10,704)       $  (18,165)
     Accounts payable                                    1,637             3,438             4,819
---------------------------------------------------------------------------------------------------
                                                        (4,843)           (7,266)          (13,346)
---------------------------------------------------------------------------------------------------

Financing activities
     Accounts receivable                                    --                --                --
     Accounts payable                                    3,514                --                --
---------------------------------------------------------------------------------------------------
                                                         3,514                --                --
---------------------------------------------------------------------------------------------------

Investing activities
     Accounts receivable                                 7,792            10,291           (11,403)
     Accounts payable                                   (6,780)            2,021            11,096
---------------------------------------------------------------------------------------------------
                                                         1,012            12,312              (307)
---------------------------------------------------------------------------------------------------

                                                    $     (317)       $    5,046        $  (13,653)
---------------------------------------------------------------------------------------------------

Cash amounts paid during the year relating to interest
expense and capital taxes are as follows:

---------------------------------------------------------------------------------------------------
                                                          2002              2001              2000
---------------------------------------------------------------------------------------------------
Interest paid                                       $   15,042        $   13,054        $   13,639
Capital taxes paid                                  $    1,084        $      793        $      470
---------------------------------------------------------------------------------------------------
</TABLE>


60
<PAGE>

16.  COMMITMENTS AND CONTINGENT LIABILITIES

     A)  COMMITMENTS

         The Company has committed to certain payments under operating leases
         over the next three years, as follows:

--------------------------------------------------------------------------------
                                         2003              2004             2005
--------------------------------------------------------------------------------
     Equipment                   $      1,636      $        769     $        352
     Office rental                      1,444             1,452              481
--------------------------------------------------------------------------------
                                 $      3,080      $      2,221     $        833
--------------------------------------------------------------------------------

     B)  LEGAL PROCEEDINGS

         The Company is involved in various legal claims associated with normal
         operations. These claims, although unresolved at the current time, are
         minor in nature and are not expected to have a material impact on the
         financial position or results of operations of the Company.

17.  UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING

     RECONCILIATION OF CONSOLIDATED FINANCIAL STATEMENTS TO UNITED STATES
     GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

     These consolidated financial statements have been prepared in accordance
     with accounting principles generally accepted in Canada ("Canadian GAAP")
     which, in most respects, conforms to accounting principles generally
     accepted in the United States of America ("U.S. GAAP"). Any significant
     differences in those principles, as they apply to the Company's statements
     of earnings, balance sheets and statements of cash flow, are as follows:

     A)  Under U.S. GAAP, the carrying value of petroleum and natural gas
         properties and related facilities, net of future or deferred income
         taxes, is limited to the present value of after tax future net revenue
         from proven reserves, discounted at 10 percent, (based on prices and
         costs at the balance sheet date), plus the lower of cost and fair value
         of unproven properties. Under Canadian GAAP, the "ceiling test" is
         calculated without application of a discount factor to future net
         revenues, but estimated future general and administrative and financing
         costs are deducted from future net revenue. Prior to January 1, 2001,
         Canadian GAAP required the test to be performed annually, whereas U.S.
         GAAP required the ceiling test to be performed at the end of each
         quarter. Subsequent to January 1, 2001, Canadian GAAP requires the
         ceiling test to be performed at the end of each quarter. The Company
         has completed a ceiling test calculation at December 31, 2002, 2001,
         2000 and 1999 with no writedown required under either Canadian or U.S.
         GAAP. At December 31, 1998 the application of the full cost ceiling
         test under U.S. GAAP would have resulted in a write-down of capitalized
         costs of $13.8 million after income tax, utilizing commodity prices at
         December 31, 1998 of $15.33/bbl for crude oil and $2.50/mcf for natural
         gas. As commodity prices were uncharacteristically low at December 31,
         1998 and considering a subsequent strengthening of prices in the first
         quarter of 1999, U.S. GAAP allows the Company to choose a different
         measurement date for purposes of calculating the full cost ceiling
         test. Accordingly, the application of the ceiling test at March 31,
         1999 did not result in a write-down, indicating that the capitalized
         costs were not in fact impaired at year end. The application of the
         full cost ceiling test under U.S. GAAP for years prior to the year
         ended December 31, 1998 did not result in a write-down of capitalized
         costs.


                                                                              61
<PAGE>

17.  UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING (CONTINUED)

     B)  Under U.S. GAAP, the provision for future site restoration costs is
         recorded as a reduction of property and equipment in the amount of $2.2
         million at December 31, 2002 (2001 - $1.6 million).

     C)  Statement of Financial Accounting Standards ("SFAS") 123, "Accounting
         for Stock-based Compensation", establishes financial accounting and
         reporting standards for stock-based employee compensation plans as well
         as transactions in which an entity issues its equity instruments to
         acquire goods or services from non-employees. As permitted by SFAS 123,
         the Company has elected to follow the intrinsic value method of
         accounting for stock-based compensation arrangements, as provided for
         in Accounting Principles Board Opinion 25 ("APB 25"). Since all options
         were granted with an exercise price equal to the market price at the
         date of the grant, no compensation cost has been charged to income at
         the time of the option grants. As discussed in Note 3(b), the Company
         retroactively adopted effective January 1, 2001, the standards of
         accounting released by the CICA for stock based compensation. These
         standards are consistent with SFAS 123.

         APB 25, as interpreted by the Financial Accounting Standards Board's
         ("FASB") interpretation 44, also requires recognition of compensation
         cost with respect to changes in intrinsic value for variable employee
         stock compensation plans. As a result of the modifications to the terms
         of employee stock options, the modified options are subject to variable
         plan accounting, which result in a compensation cost of $4.5 million
         for the year ended December 31, 2000 for U.S. GAAP purposes.

     D)  Prior to January 1, 2000, the Company recorded the renouncement of tax
         deductions resulting from the issuance of flow-though shares by
         reducing property and equipment and share capital by the estimated cost
         of the tax deductions renounced.

         U.S. GAAP requires that flow-through shares be recorded at their fair
         value without any adjustment for the renouncement of the tax deductions
         and any temporary difference resulting from the renouncement must be
         recognized in the determination of tax expense in the year incurred.
         U.S. GAAP also requires that the estimated cost of the tax deductions
         renounced be recorded as a future income tax liability rather than a
         reduction of property and equipment. Subsequent to January 1, 2000, the
         Company accounted for the estimated cost of the tax deduction renounced
         as a future tax liability and hence was consistent with U.S. GAAP. See
         Note 3(c) for the effect of this accounting policy change on property
         and equipment and future income taxes in 2000.

         The impact of recording flow-through shares at their fair value for the
         year ended December 31, 2002, was to increase the future income tax
         provision by $5.4 million (2001 - $8.7 million; 2000 - $4.7 million)
         and to increase capital stock by a corresponding amount.

     E)  Statement of Financial Accounting Standards 130, "Comprehensive
         Income", requires the reporting of comprehensive income in addition to
         net earnings. Comprehensive income includes net income plus other
         comprehensive income. Management believes that it has no other
         comprehensive income other than as described under Note 17(f).


62
<PAGE>

     F)  SFAS 133, "Accounting for Derivative Instruments and Hedging
         Activities", as amended by SFAS 137 and SFAS 138, was issued in June
         1998 by the FASB. SFAS 133 establishes new accounting and reporting
         standards for derivative instruments and for hedging activities. This
         statement requires the Company to measure all derivatives at fair value
         and to recognize them in the balance sheet as an asset or liability,
         depending on the Company's rights or obligations under the applicable
         derivative contract. Changes in the fair value of derivatives will be
         recorded each quarter in net income or other comprehensive income,
         depending on whether a derivative is designated as part of a hedge
         transaction and, if it is, depending on the type of hedge transaction.
         The ineffective portion of all hedges will be recognized in net income.
         If a derivative does not qualify as a hedging relationship, the
         derivative is recorded at fair value and changes in its fair value will
         be reported in net income. Under the current accounting policy for
         derivatives, only derivatives used in sales and trading activities are
         recorded on the balance sheet at fair value. The effective date of SFAS
         133 for the Company was January 1, 2001.

     G)  Under U.S. GAAP, discounts on long-term debt are classified as a
         reduction of long-term debt rather than as deferred financing charges.
         At December 31, 2002 deferred financing charges and senior term notes
         were reduced by $4.1 million (2001- $nil).

         DERIVATIVES
         The Company used forward contracts and options on forward contracts to
         manage the risk of fluctuations in the market price of natural gas,
         crude oil and the change in interest rates. At December 31, 2002, the
         Company had 15 forward contracts in place.

         At December 31, 2002, the natural gas and crude oil futures contracts,
         determined to be derivatives under SFAS 133, are accounted for as cash
         flow hedges and expire on various dates through December 2003. These
         contracts are recorded at fair value on the balance sheet as a $3.4
         million liability at December 31, 2002 and a $187 thousand asset at
         December 31, 2001. The effective portion of the change in fair value is
         recorded in comprehensive income, net of tax. The ineffective portion
         of the change in fair value is recorded in net income, net of tax and
         subsequently recognized as a component of revenue on the statement of
         earnings and retained earnings when the underlying product being hedged
         is purchased. The effective portion of these commodity contracts is a
         $1.7 million loss, which is recorded in comprehensive income as at
         December 31, 2002 (2001- $123 thousand gain).The ineffective portion of
         these commodity contracts is a $253 thousand loss, which is recorded in
         net income as at December 31, 2002 (2001 - $nil).

         On May 8, 2002, concurrent with the issue of the senior term notes, the
         Company entered into three interest-rate swaps, determined to be
         derivatives under SFAS 133. The swap settlement terms coincide with the
         interest obligations on the senior term notes, being May 15 and
         November 15 each year, as do the maturity and expiry date, May 8, 2009.
         The swaps are determined to be fair value hedges and the terms of the
         contract allow the Company to use the short cut method in determining
         the accounting treatment. Using this method, an increase to assets and
         senior term notes of $15.4 million was recognized at December 31, 2002
         (2001 - $nil).


                                                                              63
<PAGE>

17.  UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING (CONTINUED)

     The application of U.S. GAAP would have the following effect on net income:

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------
YEARS ENDED DECEMBER 31,                                  2002             2001           2000
-----------------------------------------------------------------------------------------------
<S>                                               <C>              <C>              <C>
Net income for the year,
     as reported                                  $     18,798     $     55,636     $   40,059
Adjustments:
     Compensation costs (c)                                                             (4,484)
     Related income taxes                                   --                           2,000
     Accounting for income taxes (d)                    (5,402)          (8,715)        (4,694)
     Other income (expense) (f)                           (253)              --             --
-----------------------------------------------------------------------------------------------
Net income for the year - U.S. GAAP               $     13,143     $     46,921     $   32,881
-----------------------------------------------------------------------------------------------
Net income per common share                       $       0.12     $       0.43     $     0.31
     - U.S. GAAP
     Basic
     Diluted                                      $       0.11     $       0.41     $     0.30
Statement of comprehensive income (e)
     Net income for the year
     - U.S. GAAP                                  $     13,143     $     46,921     $   32,881
Accountinq for hedqing (f)
                                                        (1,741)             123             --
-----------------------------------------------------------------------------------------------
Comprehensive income                              $     11,402     $     47,044     $   32,881
===============================================================================================
Depletion and depreciation expense                $     56,003     $     50,450     $   41,767
     - U.S. GAAP
==============================================================================================
Depletion and depreciation expense                $       7.81     $       7.69     $     7.04
     - U.S. GAAP per BOE produced
-----------------------------------------------------------------------------------------------
</TABLE>



64
<PAGE>

CONSOLIDATED BALANCE SHEETS

The application of U.S. GAAP would have the following effect on the balance
sheets:

<TABLE>
<CAPTION>
     ----------------------------------------------------------------------------------------------------
                                                                        DECEMBER 31, 2002
     ----------------------------------------------------------------------------------------------------
                                                                             INCREASE
                                                         AS REPORTED        (DECREASE)        U.S. GAAP
     ----------------------------------------------------------------------------------------------------
     <S>                                                  <C>               <C>               <C>
     Assets
          Property and equipment (b)                      $  708,414        $   (2,245)       $  706,169
          Accounting for hedging (f)                               -            15,402            15,402
          Deferred financing charges (g)                      13,444            (4,060)            9,384

     Liabilities
          Site restoration costs (b)                      $    2,245        $   (2,245)       $       --
          Accounting for hedging (f)                               -             3,446             3,446
          Future income taxes (f)                            205,193            (1,452)          203,741
          Senior term notes (f and g)                        260,634            11,342           271,976

     Shareholders' equity
          Capital stock (d)                               $  128,079        $   29,244        $  157,323
          Retained earnings (see schedule on pg. 66)         117,720           (31,238)           86,482
     ----------------------------------------------------------------------------------------------------


     ----------------------------------------------------------------------------------------------------
                                                                        DECEMBER 31, 2001
     ----------------------------------------------------------------------------------------------------
                                                         AS REPORTED         INCREASE         U.S. GAAP
                                                                            (DECREASE)
     ----------------------------------------------------------------------------------------------------

     Assets
          Property and equipment (b)                      $  606,920        $   (1,569)       $  605,351
          Accounting for hedging (f)                              --               187               187

     Liabilities
          Site restoration costs (b)                      $    1,569        $   (1,569)       $        -
          Future income taxes (f)                            179,192                64           179,256

     Shareholders' equity
          Capital stock (d)                               $  116,572        $   23,843        $  140,415
          Retained earnings (see schedule on pg. 66)         101,288           (23,720)           77,568
     ----------------------------------------------------------------------------------------------------
</TABLE>



                                                                              65
<PAGE>

17.  UNITES STATES ACCOUNTING PRINCIPLES AND REPORTING (CONTINUED)

     ---------------------------------------------------------------------------
     DECEMBER 31,                                          2002          2001
     ---------------------------------------------------------------------------

     Retained earnings under Canadian GAAP             $  117,720     $ 101,288
     Flow-through share differences (d)                   (29,244)      (23,843)
     Commodity derivatives (f)                             (1,994)          123
     ---------------------------------------------------------------------------

     Retained earnings under U.S. GAAP                 $   86,482     $  77,568
     ---------------------------------------------------------------------------

     CONSOLIDATED STATEMENTS OF CASH FLOW

     The application of U.S. GAAP would not change the amounts as reported under
     Canadian GAAP for cash flows provided by (used in) operating, investing or
     financing activities, except for the following:

     (i)    Unspent flow-through share proceeds which have been received at
            year-end. During 2002, the Company received $17.6 million in
            proceeds from the issuance of flow-through shares of which $17.6
            million remained unspent as at December 31, 2002 (2001 - $25.6
            million, 2000 - $12.5 million). Accordingly, under U.S. GAAP, these
            proceeds would be disclosed separately on the balance sheet as
            restricted cash and would not be treated as cash or cash equivalents
            for statement of cash flow reporting purposes. The result of this
            difference would be to disclose an increase in restricted cash as an
            investing activity and to reduce cash, end of year by $17.6 million
            at December 31, 2002 (2001 - $25.6 million, 2000 - $12.5 million);

     (ii)   The consolidated statements of cash flow include, under investing
            activities, changes in working capital for items not affecting cash,
            such as accounts payable and accounts receivable, related to the
            non-cash elements of property and equipment additions. This
            disclosure is provided in order to disclose the aggregate costs
            related to such activities and to identify the non-cash component
            thereof and to arrive at the cash amounts. This presentation is not
            permitted under U.S. GAAP;

     (iii)  The consolidated statements of cash flow include, under investing
            activities, site restoration costs. Under U.S. GAAP these costs
            would be presented under operating activities;

     (iv)   The consolidated statements of cash flow contains disclosure
            relating to cash flow from operations per share amounts. This
            presentation is not permitted under U.S. GAAP; and

     (v)    The consolidated statements of cash flow, for the year ended
            December 31, 2002 would have disclosed a negative ending cash
            balance of $2.9 million after reflecting the adjustment for
            restricted cash relating to U.S. GAAP treatment of unspent
            flow-through share proceeds (2001 - $20.4 million, 2000 - $12.5
            million). Under U.S. GAAP, this negative ending cash balance (or
            bank overdrafts) would be reflected as a financing activity in the
            consolidated statements of cash flow.


66
<PAGE>

     ADDITIONAL U.S. GAAP DISCLOSURE
<TABLE>
<CAPTION>
     ------------------------------------------------------------------------------------------------
     DECEMBER 31,                                                                2002           2001
     ------------------------------------------------------------------------------------------------
     <S>                                                                   <C>             <C>
     Accounts receivable includes the following:
          Revenue receivable                                               $   58,518      $  37,101
          Joint interest receivable                                             6,485         26,132
          Other receivables                                                    15,686         18,768
     ------------------------------------------------------------------------------------------------

                                                                           $   80,689      $  82,001
     ------------------------------------------------------------------------------------------------

     ------------------------------------------------------------------------------------------------
     DECEMBER 31,                                                                2002           2001
     ------------------------------------------------------------------------------------------------

     Accounts payable and accrued liabilities includes the following:
          Trade payables                                                   $   44,701      $  52,393
          Royalties payable                                                     8,209          5,202
          Taxes payable                                                         1,902          2,359
          Other payables                                                        8,463          4,949
     ------------------------------------------------------------------------------------------------

                                                                           $   63,275      $  64,903
     ------------------------------------------------------------------------------------------------

     The aggregate capitalized costs of oil and gas activities and costs
     incurred in oil and gas property acquisitions, development and exploration
     activities are as follows:

     CAPITALIZED COSTS

     ------------------------------------------------------------------------------------------------
     DECEMBER 31,                                                                2002           2001
     ------------------------------------------------------------------------------------------------

     Proven properties                                                     $  728,218      $ 566,074
     Unproven properties:
          Acquisition                                                         101,044        110,764
          Exploration                                                          54,205         50,205
     Accumulated depletion and depreciation                                  (175,053)      (120,123)
     ------------------------------------------------------------------------------------------------

                                                                           $  708,414      $ 606,920
     ------------------------------------------------------------------------------------------------
</TABLE>



                                                                              67
<PAGE>

17.  UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING (CONTINUED)


     COSTS INCURRED ON UNPROVEN PROPERTIES

<TABLE>
<CAPTION>
     ----------------------------------------------------------------------------------------------------------------
                               DEC 31,                              INCLUDES COSTS INCURRED IN
     ----------------------------------------------------------------------------------------------------------------
                                 2002           2002            2001           2000           1999     PRIOR YEARS
     ----------------------------------------------------------------------------------------------------------------
     <S>                 <C>              <C>              <C>            <C>            <C>             <C>
     Acquisition         $    101,044     $   (9,720)      $  38,455      $  26,006      $  17,535       $  28,768
     Exploration               54,205          4,000          23,759         17,143          9,303              --
     ----------------------------------------------------------------------------------------------------------------

                         $    155,249     $   (5,720)      $  62,214      $  43,149      $  26,838       $  28,768
     ----------------------------------------------------------------------------------------------------------------
</TABLE>

     COSTS INCURRED

<TABLE>
<CAPTION>
     -------------------------------------------------------------------------------------------
                                                             2002           2001           2000
     -------------------------------------------------------------------------------------------
     <S>                                                <C>            <C>            <C>
     Acquisition costs (net of disposition)
          Proven properties                             $  27,157      $  30,716      $     241
          Unproven properties                              (9,720)        38,455         26,006
     Development costs
          Development of proven undeveloped reserves       21,280         16,088         19,573
          Other                                            52,971         27,229         48,582
     Exploration costs                                     63,462         75,417         23,992
     -------------------------------------------------------------------------------------------

     Total costs incurred                               $ 155,150      $ 187,905      $ 118,394
     -------------------------------------------------------------------------------------------
</TABLE>

     Costs are transferred into the depletion base on an ongoing basis as the
     undeveloped properties are evaluated and proven reserves are established or
     impairment determined. Pending determination of proven reserves
     attributable to the above costs, the Company cannot assess the future
     impact on the amortization rate.

     ---------------------------------------------------------------------------
     DECEMBER 31,                                          2002          2001
     ---------------------------------------------------------------------------
     Future income tax liabilities
          Property and equipment                        $ 214,233     $ 188,880
     Future income tax assets
          Other temporary differences                      (5,175)       (5,315)
          Abandonment costs                                  (709)         (669)
          Loss carry forward                               (1,360)       (2,162)
          Other                                            (3,248)       (1,478)
     ---------------------------------------------------------------------------
     Future income taxes                                $ 203,741     $ 179,256
     ---------------------------------------------------------------------------



68
<PAGE>

     RECENT ACCOUNTING PRONOUNCEMENTS

     In August 2001, the Financial Accounting Standards Board ("FASB") issued
     Statement of Financial Accounting Standard ("SFAS") 143, "Accounting for
     Asset Retirement Obligations". This Statement addresses financial
     accounting and reporting for obligations associated with the retirement of
     tangible long-lived assets and the associated asset retirement costs. SFAS
     143 requires an entity to record the fair value of an asset retirement
     obligation as a liability in the period in which it incurs a legal
     obligation associated with the retirement of a tangible long-lived asset.
     SFAS 143 also requires the entity to record the contra to the initial
     obligation as an increase to the carrying amount of the related long-lived
     asset (i.e., the associated asset retirement costs) and to depreciate that
     cost over the remaining useful life of the asset. The liability is adjusted
     at the end of each period to reflect the passage of time (i.e., accretion
     expense) and changes in the estimated cash flows underlying the initial
     fair value measurement. Entities are required to adopt SFAS 143 for fiscal
     years beginning after June 15, 2002. The Company will adopt SFAS 143 on
     January 1, 2003, and expects it may have a material impact on the
     consolidated financial statements.

     In October 2001, the FASB issued SFAS 144, "Accounting for the Impairment
     or Disposal of Long-Lived Assets". SFAS 144 supersedes SFAS 121,
     "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
     Assets to be Disposed of", and certain provisions of APB Opinion 30,
     "Reporting the Results of Operations, Reporting the Effects of Disposal of
     a Segment of a Business, and Extraordinary, Unusual and Infrequently
     Occurring Events and Transactions". SFAS 144 establishes standards for
     long-lived assets to be disposed of, and redefines the valuation and
     presentation of discontinued operations. SFAS 144 is effective for fiscal
     years beginning after December 15, 2001, and interim periods within those
     fiscal years. The adoption of SFAS 144 did not have a material effect on
     the Company's financial position, results or operations, or cash flows.

     In June 2002, the FASB issued SFAS 146, "Accounting for Costs Associated
     with Exit or Disposal Activities". SFAS 146 requires recording costs
     associated with exit or disposal activities at their fair values when a
     liability has been incurred. Under previous guidance, certain exit costs
     were accrued upon management's commitment to an exit plan, which is
     generally before an actual liability has been incurred. The requirements of
     SFAS 146 are effective prospectively for exit or disposal activities
     initiated after December 31, 2002.

     In November 2002, the FASB issued FASB Interpretation 45, "Guarantor's
     Accounting and Disclosure Requirements for Guarantees, Including Indirect
     Guarantees of Indebtedness of Others" (FIN 45). FIN 45 requires that upon
     issuance of a guarantee, a guarantor must recognize a liability for the
     fair value of an obligation assumed under a guarantee. FIN 45 also requires
     additional disclosures by a guarantor in its interim and annual financial
     statements about the obligations associated with guarantees issued. The
     recognition provisions of FIN 45 are effective for any guarantees issued or
     modified after December 31, 2002. The disclosure requirements are effective
     for financial statements of interim or annual periods ending after December
     15, 2002. Management does not expect that the adoption of FIN 45 will have
     a material effect on the Company's financial position, results of
     operations or cash flow.


                                                                              69
<PAGE>

     In December 2002, the FASB issued SFAS 148, "Accounting for Stock-Based
     Compensation - Transition and Disclosure". SFAS 148 amends SFAS 123
     "Accounting for Stock-Based Compensation," to provide alternative methods
     of transition for a voluntary change to the fair value based method of
     accounting for stock-based employee compensation. In addition, SFAS 148
     amends the disclosure requirements of SFAS 123 to require prominent
     disclosures in both annual and interim financial statements about the
     method of accounting for stock-based employee compensation and the effect
     of the method used on reported results. SFAS 148 is effective for fiscal
     years beginning after December 15, 2002. The expanded annual disclosure
     requirements and transition provisions are effective for fiscal years
     ending after December 15, 2002. The interim disclosure provisions are
     effective for financial reports containing financial statements for interim
     periods beginning after December 15, 2002. SFAS 148 has no material impact
     on the Company's financial position, results of operations, or cash flow,
     as the Company does not plan to adopt the fair value method of accounting
     for stock options at the current time. Management has included the required
     disclosures in Note 11 of the consolidated financial statements.



70
<PAGE>

     SUPPLEMENTAL RESERVE
         INFORMATION (UNAUDITED)

The net proven oil and natural gas reserve estimates as at December 31, 2002,
2001 and 2000 set forth below were prepared in accordance with guidelines
established by the Securities and Exchange Commission and accordingly were based
on existing economic and operating conditions. Oil and natural gas prices in
effect as of the respective year ends were used without any escalation except in
those instances where the sale is covered by contract, in which case the
applicable contract price is used. Operating costs, royalties and future
development costs were based on current costs with no escalation.

There are numerous uncertainties inherent in estimating quantities of proven
reserves and in projecting the future rates of production and timing of
development expenditures. The following reserve data represents estimates only
and should not be construed as being exact. Moreover, the present value should
not be construed as the current market value of the Company's oil and natural
gas reserves or the costs that would be incurred to obtain equivalent reserves.
All of the reserves are located in Canada.

ESTIMATED QUANTITIES OF RESERVES

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------
                                                                YEARS ENDED DECEMBER 31,
---------------------------------------------------------------------------------------------------------------------
                                              2002                        2001                        2000
---------------------------------------------------------------------------------------------------------------------
                                    CRUDE OIL                    CRUDE OIL                    CRUDE OIL
                                       AND         NATURAL          AND         NATURAL         AND          NATURAL
                                       NGLS          GAS            NGLS          GAS           NGLS          GAS
                                     (MBBLS)        (MMCF)         (MBBLS)       (MMCF)       (MBBLS)        (MMCF)
---------------------------------------------------------------------------------------------------------------------
<S>                                    <C>         <C>             <C>         <C>            <C>          <C>
Balance, beginning of year             9,777       262,448         9,423       223,761        10,682       181,759
     Revisions of
         previous estimates              529        11,712           313        (3,186)       (2,524)        1,715
     Extensions, discoveries and
         other additions               1,829        58,853         1,611        63,248         1,399        60,495
     Acquisitions of minerals in
         place                           514        18,805           301         7,412         1,809         8,761
     Dispositions of minerals in
         place                           (84)       (5,343)          (45)         (382)         (180)       (3,930)
     Production                       (1,842)      (31,974)       (1,826)      (28,405)       (1,763)      (25,039)
---------------------------------------------------------------------------------------------------------------------
Balance, end of year                  10,723       314,501         9,777       262,448         9,423       223,761
=====================================================================================================================

Proven developed reserves
     Balance, beginning of year        8,938       232,319         8,576       187,969         8,629       156,939
     Balance, end of year              9,723       293,836         8,938       232,319         8,576       187,969
---------------------------------------------------------------------------------------------------------------------
</TABLE>


                                                                              71
<PAGE>

SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)(CONTINUED)

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

The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein
Relating to Proven Oil and Natural Gas Reserves ("Standardized Measure") does
not purport to present the fair market value of the Company's oil and natural
gas properties. An estimate of such value should consider, among other factors,
anticipated future prices of oil and natural gas, the probability of recoveries
in excess of existing proven reserves and acreage prospects, and perhaps
different discount rates. It should be noted that estimates of reserve
quantities, especially from new discoveries, are inherently imprecise and
subject to substantial revisions.

Under the Standardized Measure, future cash inflows were estimated by applying
year end prices, adjusted for contracts currently in place to deliver production
to the estimated future production of year end proven reserves. Future cash
inflows were reduced by estimated future production and development costs based
on year end costs to determine pre-tax cash inflows. Future taxes were computed
by applying the statutory tax rate to the excess of pre-tax cash inflows over
the Company's tax basis in the associated proven oil and natural gas properties.
Tax credits and net operating loss carry forwards were also considered in the
future income tax calculation. Future net cash inflows after income taxes were
discounted using a 10 percent annual discount rate to arrive at the Standardized
Measure.

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------
YEARS ENDED DECEMBER 31,                                   2002          2001          2001
--------------------------------------------------------------------------------------------
(Cdn$000s)
<S>                                                 <C>           <C>           <C>
Future cash flows                                   $2,460,747    $1,270,787    $2,524,446
Future production costs                               (507,576)     (431,127)     (382,540)
Future development costs (1)                           (56,209)      (41,943)      (41,035)
--------------------------------------------------------------------------------------------

Future net cash flows                                1,896,962       797,717     2,100,871
Income taxes                                          (733,434)     (264,960)     (907,123)
--------------------------------------------------------------------------------------------

Total undiscounted future net cash flows             1,163,528       532,757     1,193,748
10% annual discount for estimated timing
     of cash inflows                                  (509,831)     (215,296)     (483,879)
--------------------------------------------------------------------------------------------

Standardized measure of discounted future net cash
     flows                                          $  653,697     $ 317,461     $ 709,869
--------------------------------------------------------------------------------------------
</TABLE>

(1)  The Company estimates that it will incur $11.3 million in 2003, $10.0
     million in 2004 and $ nil in 2005 to develop proved undeveloped reserves.


72
<PAGE>

The following table sets forth an analysis of changes in the Standardized
Measure of Discounted Future Net Cash Flows from proved oil and natural gas
reserves:

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------
YEARS ENDED DECEMBER 31,                                              2002              2001              2000
------------------------------------------------------------------------------------------------------------------
(CDN$000s)
<S>                                                                <C>               <C>               <C>
Beginning of year                                                  $ 317,461         $ 709,869         $ 271,486
     Sales of production, net of production costs                   (126,745)         (151,724)         (137,110)
     Net change in sales prices, net of production costs             502,652          (807,804)          783,990
     Extensions, discoveries and additions                           198,811           127,656           116,197
     Changes in estimated future development costs                   (58,187)          (48,528)          (26,630)
     Development costs incurred during the period
         which reduced future development costs                       66,881            58,982            51,305
     Revisions in quantity estimates                                  70,721            (2,099)           88,175
     Accretion of discount                                            42,348           111,245            35,497
     Purchase of reserves                                             55,129            17,976            87,440
     Sales of reserves                                               (20,051)           (1,517)           (7,783)
     Net change in income tax                                       (234,813)          389,962          (395,612)
     Changes in production rates (timing) and other                 (160,510)          (86,557)         (157,086)
------------------------------------------------------------------------------------------------------------------

Standardized measure, end of year                                  $ 653,697         $ 317,461         $ 709,869
------------------------------------------------------------------------------------------------------------------
</TABLE>

<PAGE>

                                                                      DOCUMENT 4
                                                                      ----------



ELECTION OF DIRECTORS

The articles of the Corporation stipulate that the board of directors of the
Corporation (the "BOARD") shall consist of a minimum of one and a maximum of 11
directors. The Board currently consists of five directors. Management will
propose the 6 persons named below, all of whom are currently directors of the
Corporation other than Mr. John Thomson, as nominees for election as directors
to continue in office until the next succeeding annual meeting of the
Shareholders or until their successors are duly elected or appointed.

If any of the nominees named below is for any reason unavailable to serve as a
director, proxies in favour of Management will be voted for another nominee in
the discretion of the persons named in the form of proxy unless the Shareholder
has specified in the proxy that his or her shares are to be withheld from voting
on the election of directors. THE BOARD UNANIMOUSLY RECOMMENDS THAT SHAREHOLDERS
VOTE IN FAVOUR OF EACH OF THE NOMINEES.

<TABLE>
<CAPTION>
                                                                                              NUMBER OF COMMON SHARES
                                                                                                 OF THE CORPORATION
                                                                                                OWNED, CONTROLLED OR
   NAME AND MUNICIPALITY OF                                                       DIRECTOR      DIRECTED AT THE DATE
          RESIDENCE                          PRINCIPAL OCCUPATION                   SINCE            HEREOF(4)
=======================================================================================================================
<S>                             <C>                                              <C>          <C>
Mel F. Belich, Q.C. (1)         President of Enbridge International Inc., an        1993               1,814,616
Calgary, Alberta                energy transportation and distribution company

Irvine J. Koop, P.Eng(2)        Chairman and Chief Executive Officer, IKO           1996                 459,000
Calgary, Alberta                Resources Inc.

John W. Preston                 Account Executive, Sun Microsystems of Canada       1993               1,985,246
Calgary, Alberta                Inc., a computer company

Jeffrey T. Smith, P.Geol.(3)    Independent Businessman                             1999                  36,000
Calgary, Alberta

Ernest G. Sapieha, C.A.         President & Chief Executive Officer of the          1993               6,684,861
Calgary, Alberta                Corporation

John A. Thomson, C.A.           Independent Businessman                          Nominee for              10,000
Calgary, Alberta                                                                  election
</TABLE>

<PAGE>

NOTES:

(1)  Chairman of the Corporation and Chairman of the Governance and Compensation
     Committee.

(2)  Chairman of the Audit, Finance and Risk Committee.

(3)  Chairman of the Engineering, Environmental, Health and Safety Committee.

(4)  The information with respect to the shareholdings of the nominees for
     election as directors has been furnished by the respective nominees.


<PAGE>


Other than Mr. Thomson, each of the nominees for election as directors was
elected as a director to his present term of office by a vote of the
Corporation's shareholders at a meeting of shareholders held on June 4, 2002.
Mr. Thomson, prior to July 2001, served as Vice President Corporate Development
from October 2000 and a director from September 1999 of Avid Oil & Gas Ltd, an
oil and gas company. From June 1983 to November 1999, he was Senior Vice
President and Chief Financial Officer of Renaissance Energy Ltd., an oil and gas
company. Mr. Thomson obtained a Bachelor of Business Administration degree from
the University of New Brunswick in 1972 and qualified as a chartered accountant
in 1974.

All of the directors of the Corporation, other than Mr. Sapieha, are independent
and unrelated to the Corporation and its affiliates. The Board has established
an Audit, Finance and Risk Committee, an Engineering, Environmental, Health and
Safety Committee, and a Governance and Compensation Committee. Each of these
committees consists of all of the directors of the Corporation, other than Mr.
Sapieha. For information about such committees and the Corporation's policies
with respect to corporate governance, see "Statement of Corporate Governance
Practices".


                                        2